Enbridge Annual Report 1999

← All annual reports

FY1999 Annual Report · Enbridge

Loading PDF…

1999 ANNUAL REPORT

1 Highlights

2 Letter to Shareholders

8 Operations Review

14 Management’s Discussion and Analysis

31 Financial Statements and Notes

57 Supplementary Information

58 Five Year Consolidated Highlights

60 Shareholder and Investor Information

Enbridge bridges the gap between energy supply and the customer, providing seamless service and

delivery. Enbridge is also bridging the gap from the present to an innovative and exciting energy future.

As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest

crude oil and liquids pipeline system. The Company also is involved in liquids marketing and

international energy projects, and has a growing involvement in the natural gas transmission and

midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural

gas distribution company, which provides gas to 1.5 million customers in Ontario, Quebec and New

York State. Enbridge is also involved in the distribution of electricity, and provides retail energy products

and services to a growing number of Canadian and United States markets. The Company employs

approximately 5,500 people, primarily in Canada, the United States and Latin America. Enbridge

common shares trade on the Toronto Stock Exchange under the symbol “ENB”, and on The NASDAQ

National Market in the United States under the symbol “ENBR”. Information about Enbridge is available

on the World Wide Web at www.enbridge.com.

Inuvik

Norman Wells

Zama

Fort St. John

Fort McMurray

Edmonton

Hardisty

Casper

Salt Lake City

Ottawa

Montreal

Cornwall

Toronto

Dawn

Chicago

Toledo

Patoka

Liquids Pipelines

Gas Pipelines

Gas Distribution

Electric Power Distribution

Gas Gathering and Processing

Coveñas

Jose Terminal

Cusiana/
Cupiagua

Bogota

Enbridge Inc.

LIQUIDS PIPELINES

(cid:2)

Enbridge Pipelines Inc.
Enbridge Pipelines (NW) Inc.
Enbridge Pipelines (Athabasca) Inc.
Enbridge Pipelines (Saskatchewan) Inc.
Enbridge Pipelines (North Dakota) Inc.
Enbridge Pipelines (Toledo) Inc.
Lakehead Pipe Line Partners, L.P. (15.3%)

(cid:2) Mustang Pipe Line Partners (30%)
Chicap Pipe Line Company (23%)
(cid:2)
Frontier Pipeline Company (44%)

(cid:2)

GAS DISTRIBUTION

(cid:2)

Enbridge Consumers Gas
(cid:2) Gazifère Inc. – an Enbridge Company
(cid:2) Niagara Gas Transmission Limited – an Enbridge Company
(cid:2) St. Lawrence Gas Company, Inc. – an Enbridge Company
Noverco Inc. (32%)
(cid:2) Gaz Métropolitain and Company, Limited Partnership (77%)

(cid:2) Vermont Gas Systems, Inc. (100%)
(cid:2) TQM Pipeline and Company, Limited Partnership (50%)

(cid:2)

Enbridge Gas New Brunswick Inc. (63%)

INTERNATIONAL

Enbridge International Inc.
(cid:2) Oleoducto Central S.A. (17.5%)
(cid:2) Sociedad Williams Enbridge Compania (G.P.) (45%)
Enbridge Technology Inc.

GAS PIPELINES AND NEW BUSINESS DEVELOPMENT

Alliance Pipeline Limited Partnership (21.4%)
Vector Pipeline Limited Partnership (45%)
AltaGas Services Inc. (40%)
Inuvik Gas Ltd. (33 1/3%)
Cornwall Electric – an Enbridge Company

ENERGY SERVICES

Enbridge Services Inc.
Enbridge (Pennsylvania) Inc.
Enbridge Petroleum Exchange Inc.
Tidal Energy Marketing Inc. (50%)

(cid:2)

ALL SECTIONS OF A BRIDGE MUST BE

INTEGRATED WITH AND REINFORCE ALL

OTHER SECTIONS. AT ENBRIDGE, ALL

BUSINESS SEGMENTS STRENGTHEN

AND SUPPORT EACH OTHER. EACH

SEGMENT MUST SUCCEED ON ITS OWN,

BUT THE SUCCESS OF THE ENTERPRISE

AS A WHOLE IS PARAMOUNT.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Highlights

FINANCIAL1

(Canadian dollars in millions, except per share amounts)

Earnings applicable to common shareholders
Cash provided from operating activities
Dividends paid on common shares
Per common share amounts 2 (dollars per share)

Earnings
Cash provided from operating activities
Dividends

Return on average common shareholders’ equity
Debt to debt plus shareholders’ equity at year end

OPERATING

Liquids Pipelines 3

Deliveries (thousands of barrels per day)
Barrel miles (billions)
Average haul (miles)

Gas Distribution 4

Gas distribution volumes (billions of cubic feet)
Number of active customers 5 (thousands)
Degree day deficiency 6 (degrees Celsius)

Actual
Forecast based on normal weather

1999

287.9
495.1
186.4

1.91
3.28
1.195
14.3%
67.4%

1998

240.9
312.4
168.3

1.66
2.15
1.120
13.8%
69.7%

1997

217.3
437.8
147.1

1.58
3.18
1.060
14.2%
67.7%

1999

1998

1997

2,023
696
946

402
1,466

3,460
4,060

2,136
771
989

397
1,414

3,352
4,079

2,083
771
1,014

428
1,362

4,011
4,003

1 Prior year amounts have been restated to conform to the segmentation and presentation adopted in 1999.
2 Prior year per common share amounts have been restated to give effect to the two for one stock split that occurred on May 10, 1999.
3 Liquids Pipelines operating highlights include the statistics of the 15.3% owned portion of the mainline system located in the

United States.

4 Highlights of Gas Distribution reflect the results of Enbridge Consumers Gas (The Consumers’ Gas Company Ltd.) and other gas

distribution assets on a quarter lag basis of consolidation.

5 The number of active customers at year end reflects 58,000 new connections made to the Gas Distribution system during 1999.
6 Degree day deficiency is a measure of coldness. It is calculated by accumulating for each day in the fiscal period the total
number of degrees by which the daily mean temperature fell below 18 degrees Celsius. The figures given are those accumulated
in the Toronto area.

Earnings Per
Common Share
(dollars per share)

1
9
1

6
6
1

8
5
1

5
4
1

5
1
1

Dividends Per
Common Share
(dollars per share)

5
9
1
1

0
2
1
1

0
6
0
1

0
0
0
1

5
1
0
1

T H E E N E R G Y B R I D G E

1 9 9 9 : A T I M E L I N E F O R A C H I E V E M E N T

January

The SEP II mainline expansion program
was completed, adding 100,000 barrels
per day of capacity in Canada and
170,000 barrels per day into Chicago.

The Enbridge Petroleum Exchange
began operation of Canada’s first
Internet-based crude oil exchange.

Letter to Shareholders

Enbridge made significant strides in 1999. Earnings
reached record levels. Dividends again increased. And
we attained a number of key operational objectives.

The fundamentals of our business remain strong and
we are well positioned to take advantage of our
numerous long term growth opportunities. We will
continue to pursue our strategies for profitable growth
to generate superior value for our shareholders.

Brian F. MacNeill
President &
Chief Executive Officer

1999: CONTINUING THE PATTERN
OF PROFITABLE GROWTH

Financial Highlights:

“BRIDGES SPAN GAPS AND BRING

PEOPLE TOGETHER. ENBRIDGE

BRIDGES THE GAP BETWEEN ENERGY

SUPPLY AND THE CUSTOMER,

PROVIDING SEAMLESS SERVICE AND

DELIVERY. ENBRIDGE IS ALSO

BRIDGING THE GAP FROM THE

PRESENT TO AN INNOVATIVE AND

EXCITING ENERGY FUTURE.”

Earnings applicable to common shareholders
increased to a record $287.9 million, or $1.91 per
share, in 1999, up from $240.9 million, or $1.66
per share, in 1998. Once again, we achieved our
target of double-digit growth in earnings per share.
Over the last four years, compound annual growth
in earnings per common share amounted to
13.5%, and this was achieved despite the record
warm winters in 1999 and 1998 that adversely
affected Gas Distribution earnings by an estimated
$71 million. Notwithstanding superior earnings
growth, we continue to maintain the relatively low
business risk profile of the Company.

Earnings generated a 14.3% return on common
shareholder equity, up from 13.8% in 1998 and in
line with the five-year average of 14.1%. This result
illustrates the profitability of our core businesses
and new investments, and the essence of the value
proposition we offer our shareholders — superior
returns with relatively low risk.

Enbridge has increased its quarterly dividends by an
average of 5% each year since 1996, and in 1999
we increased the quarterly dividend to $0.3025
per common share. Annual increases are in line with
the strong earnings and cash flow over the last five
years, while the dividend payout ratio has declined,
which is consistent with our growth profile.

In 1999, we invested $1.2 billion in the business,
which is down from the record $1.6 billion spent in
1998. Although profitable in their own right, these
investments position Enbridge for future growth in
earnings. This level of spending requires continuous
access to capital markets, and in 1999 we raised
approximately $1 billion in debt and equity, a clear
indication of the confidence that the investment
community places in the long term fundamentals
of our business.

Our financial position is strong. At year end, our
book equity to total capitalization was 33%, in line
with our target capital structure and an improve-
ment over the 30% in 1998. In addition to internally
generated funds, we also have access to some
$2 billion in unutilized credit facilities to finance
significant opportunities.

Operating Highlights:

In addition to our financial success, Enbridge achiev-
ed a number of operational milestones in 1999.

We strengthened the existing energy delivery busi-
nesses and added to overall pipeline capacity
through completion of a number of liquids pipeline
expansions and extensions including the System
Expansion Program Phase II (SEP II), Phase I of the
Terrace expansion, the new Athabasca Pipeline and
related tank terminal, the reversal of Line 9 to
transport crude oil from Montreal to Sarnia, and
extension of the United States system to deliver
crude oil to a refinery in Toledo, Ohio.

March

The Vector Pipeline received regulatory approval from
the National Energy Board for the Canadian portion of
the system in March. Final U.S. approval was received
from the Federal Energy Regulatory Commission in May.
In September, Westcoast Energy Inc. joined the project.
Vector Pipeline, which is scheduled for first service in
October 2000, will transport natural gas from Chicago
to the Dawn, Ontario, hub.

Enbridge announced a proposal for a new pipeline in the
southern United States to transport crude oil from the
eastern Gulf Coast to western Gulf Coast refineries. The
project, which is currently seeking shipper commitments,
is called the Alligator Pipeline.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

April

The Ontario Energy Board approved Performance
Based Regulation (PBR) for Enbridge Consumers Gas
for the years 2000 through 2002. PBR introduces an
incentive mechanism to the traditional cost of service
methodology, with shareholders and customers
benefiting from cost reductions and productivity gains.

We expanded the Enbridge Consumers Gas distri-
bution network with the addition of 12 new
communities and 58,000 new connections, and
won the natural gas distribution franchise for the
province of New Brunswick.

We successfully negotiated a five-year extension to
the Incentive Tolling Agreement for Enbridge
Pipelines’ Canadian mainline liquids pipeline
system, and received regulatory approval to imple-
ment Performance Based Regulation for Enbridge
Consumers Gas.

We continued to develop a significant presence in
the natural gas transmission business through
involvement in the Alliance and Vector pipelines —
both of which are on track for start up in October
2000 — and entered into the midstream gas busi-
ness with a 40% investment in AltaGas Services Inc.

We successfully negotiated an interim facilities
operating contract in Venezuela which, coupled with
several successful technology transfer contracts,
helped to further increase International earnings
through the year.

We unbundled ancillary assets from the gas distri-
bution utility, and completed the transition to a fully
unregulated retail products and services business.

We announced plans to establish a shared services
business unit to provide information technology,
billing and fleet management services to Enbridge’s
growing portfolio of energy distribution and services
businesses in Central and Atlantic Canada, and
potentially to third party customers.

We also celebrated our 50th anniversary. It was
an opportunity to look back at what we were — a
Western Canadian crude oil pipeline with one share-
holder — compared with what we are today —
a widely held, publicly traded, diversified, international
leader in energy transportation and distribution.

THE REASONS FOR OUR SUCCESS

Clearly, 1999 was a successful year. But this
success was really a continuation of the pattern of
profitable growth we have established over the last
five years. We believe this success stems from our
focused approach to the business, how we develop
and refine our strategies for growth, and how we
measure performance.

Approach To The Business:

There are many things we do well at Enbridge, as
do other companies. But there are also some
things that we think set us apart:

(cid:2) First and foremost, our emphasis is not on increas-
ing the size of the Company. It is on adding
economic value. We won’t grow for growth’s sake,
and sometimes this means rejecting projects that
don’t make the grade, or saying “no” to business
opportunities that are fashionable at the moment
but don’t fit with our philosophy or what our share-
holders expect.

(cid:2) Our approach is to develop our core businesses and
then leverage these assets and our capabilities to
expand to complementary businesses. Generally,
any new business must be complementary to our
existing core business platform.

(cid:2) We develop our people so that we are well positioned
for long term success. Our strength stems from our
Board of Directors, a strong management team
and our 5,500 employees. Employees participate
in decision-making and share in the success, so
our goals are aligned with those of our shareholders.

(cid:2) We carefully evaluate business prospects to
ensure they have the appropriate balance between
risk and reward while still meeting our risk para-
meters. We look to commercial terms and
operational synergies to mitigate risks.

T H E E N E R G Y B R I D G E

Enbridge shareholders approved a two-for-one
stock split, increasing availability of common
shares for purchase by the public and enhancing
the liquidity and trading of the shares.

May

Construction of the Enbridge Pipelines (Athabasca)
Inc. system, from the oil sands to Hardisty, Alberta,
was completed by the beginning of April, and first oil
was received at Hardisty in May.

Line 9 began service with the pipeline operating with
partially reversed flow, transporting crude oil from
Montreal to Westover, Ontario. Full reversal from
Montreal to Sarnia began in September.

Enbridge announced plans to acquire an interest
in AltaGas Services Inc. to establish a strategic
alliance for midstream gas services — including
gathering, processing, upstream storage and
liquids extraction — for Canadian gas producers.
As of September, Enbridge had acquired an
interest of approximately 40%.

(cid:2) Finally, we take a great deal of pride in achieving the targets
we set for ourselves. It has been this success in meeting
targets that has earned us the credibility we have with investors
and other stakeholders.

Developing And Refining Strategies:

Planning is a continuous process, and at Enbridge we plan,
re-tool the plan, and then we do still more planning.

Our primary planning horizon is five years, but we also look
farther out so we can identify and capitalize on underlying
trends, both within and outside the industry. Our businesses
are changing rapidly. We know that to succeed we need to
anticipate our customers’ needs and be ready with new prod-
ucts and services when they are needed. Or to use a hockey
analogy, just like Wayne Gretzky, we understand the need to
go where the puck will be, not where it is now.

Our current strategic plan includes a Company-wide focus
on enhancing the profitability of energy delivery operations by
incorporating incentive provisions in rate-setting mechanisms
for existing and new businesses, and then managing opera-
tional performance to maximize the benefits to customers
and shareholders. There are also a number of focused strate-
gic thrusts for growth and development initiatives within or
complementary to the Company’s two core businesses:

(cid:2) Developing the Company’s strong base of existing delivery busi-
nesses through expansion and geographic extension within North
America, and through attractive international opportunities;

(cid:2) Developing and acquiring field gathering, terminaling and
marketing businesses that are complementary to the liquids
pipeline business, and pursuing significant growth opportu-
nities for natural gas pipeline and gas gathering, processing
and marketing investments;

(cid:2) Leveraging the position of Enbridge Consumers Gas to estab-
lish a new source of growth from investment in and/or provision
of services to electric power distribution systems; and

(cid:2) Building a base for potential longer term growth through a
measured entry into unregulated retail energy services using
a transfer of competencies and assets previously developed
within Enbridge Consumers Gas.

Measuring Performance:

We take a very critical look at how we are doing relative to our
plans. Generally, we “stay the course” but refine our strate-
gies and tactics as needed. We’re not afraid to make course
corrections along the way, always keeping in mind our over-riding
objective of providing superior returns for our shareholders.

New opportunities must not only make sense as part of
overall corporate performance, they must make sense on a
stand-alone basis. Our goal is to make sure that our highly
profitable core businesses do not subsidize less than
optimal projects that don’t meet our strategic objectives.
Once the project is complete and operational, we also look
back to see if our assumptions were valid so we can improve
on the decision-making process.

In addition to traditional financial indicators such as earn-
ings per share and return on equity, we use a variety of other
indicators to prioritize and select new projects:

(cid:2) Operational and technical performance, which includes stan-

dards for environmental protection, health and safety;

(cid:2) Economic value added, which we measure by comparing

returns to our cost of capital; and

(cid:2) Customer contact and services standards, an increasingly
important factor which will determine success in a deregu-
lated energy environment.

LOOKING AHEAD

The past year was pivotal in positioning Enbridge for contin-
ued growth in the year 2000 and beyond.

There is considerable upside for our liquids business.
Although oil prices recovered in 1999, drilling levels and
volume growth lagged the recovery. However, increased
Western Canadian drilling and the numerous oil sands and
heavy oil projects announced and under way in Alberta are
expected to boost throughput to pre-1999 levels by year end
2000 with further increases thereafter. The investments
we have made in additional pipeline capacity will enable us
to adapt quickly to increasing supply from Western Canada,
and reap the rewards.

Enbridge and the Canadian Association of Petroleum
Producers announced extension for another five years
of the Incentive Tolling Agreement, for the years
2000 through 2004, for the Canadian mainline
liquids pipeline system.

June

Alliance Pipeline began construction in Canada and the
United States. Alliance, in which Enbridge has a 21.4%
interest, is scheduled to begin transporting natural gas
from Western Canada to the Chicago area in October
2000. Initial capacity will be approximately 1.3 billion
cubic feet per day. As of year end, 72% of mainline
pipe had been installed.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

September

Enbridge Gas New Brunswick was awarded the
gas distribution franchise for the province of New
Brunswick. Enbridge has a 63% interest in the
project which will involve investment of approx-
imately $300 million over 20 years.

Western Canada will continue to provide substantial volume
growth, and the extension of our mainline incentive tolling
agreement for another five years, from 2000 to 2004, will
ensure that Enbridge and its customers continue to share
in cost savings from efficient operation of the pipeline system.
However, we are also diversifying our sources of liquids supply
to other basins and we are making progress on this front.

The growth in the gas distribution franchise continues to
surpass our estimates. We expect to benefit from the record
year of customer additions in 1999, a modest increase in
allowed return on equity for 2000, and the return to more
normal weather patterns. Our return on capital should also
improve with the introduction of targeted Performance Based
Regulation (PBR) for three years beginning in 2000. After that,
comprehensive PBR is expected to provide further upside.

The shared services model we adopted in 1999 will assist
in maximizing use of resources and leveraging cost effi-
ciencies and intellectual capital across operating units.

Despite these efforts, the returns allowed by Canadian reg-
ulators continue to be unsatisfactory. Under these conditions,
a major challenge for Enbridge — and for all Canadian
pipeline and utility companies — will be attracting new funds
for our growth plans. To that end, we plan to work with our col-
leagues, customers and provincial and federal regulators to
address this.

With the unbundling of ancillary assets from the gas distri-
bution utility last October, we now have the critical mass to
operate effectively and capitalize on deregulation of energy
services. We will continue to assess opportunities to extend
our reach and develop a wide product line. We will also con-
tinue our measured approach to establish a sound base of
profitable operations.

We will continue to seek international investments. But we
only pursue opportunities where we can leverage our capa-
bilities and bring something other than financial resources to
the table. In January 1999, we announced that we were
acquiring a 45% interest in the recently completed Jose crude
oil storage and marine terminal in Venezuela. Along with our

partners, we have been successfully operating the facility
since April. However, the issuance of a Venezuelan Minister-
ial permit needed to close the transaction was delayed and
we hope to close the transaction in the first half of 2000.

In just a short time, Enbridge has become a major player in
the natural gas transmission and midstream businesses.
The Alliance and Vector pipeline projects and the acquisition
of a 40% interest in AltaGas Services provide the foundation
for future growth in natural gas infrastructure for Enbridge.

We also have a number of other opportunities that provide
us with further confidence that we can sustain the level of
growth that our shareholders have become accustomed to.

Our long term view of natural gas is very positive as strong
United States demand will drive further infrastructure devel-
opment to connect new basins such as the Alaska North
Slope, and the Mackenzie Delta and the East Coast of
Canada. Enbridge is well positioned to participate in north-
ern gas development — we are the only Canadian operator
with far northern facilities through both our Norman Wells
liquids pipeline and our Inuvik gas pipeline and distribution
system. We have been actively developing project design
alternatives for consideration by resource owners, recogniz-
ing that any such project will likely involve a consortium of
producers and pipeline companies.

Despite a slowdown in the privatization of Municipal Elec-
tric Utilities in Ontario, we are excited about the prospects
for energy convergence. Through Canada’s premier natural
gas distribution company — Enbridge Consumers Gas — we
are perhaps the best positioned to achieve synergies by
sharing services between gas and electric distribution
systems serving the same customer base.

Finally, there are a number of acquisition opportunities we
are pursuing to extend our core businesses. As an inde-
pendent company with a long history of managing infrastructure
assets, we have a natural advantage in acting as an aggre-
gator of pipeline assets that become non-strategic to existing
owners, including those we expect to be shed from the mega-
mergers of large integrated oil companies.

T H E E N E R G Y B R I D G E

October

First commercial natural gas development north
of Canada’s Arctic Circle became a reality with
start-up of the Inuvik Gas Project to distribute
natural gas to the town of Inuvik. Enbridge has
a 33 1/3% interest.

Unbundling took effect October 1, 1999, with
Enbridge Consumers Gas remaining a regulated
gas distribution company, and Enbridge Services
becoming the provider of energy products and
services in a non-regulated environment.

The first phase of the Terrace Expansion on
Enbridge’s mainline system was completed, adding
170,000 barrels per day of capacity for heavy and
synthetic oils. Pipeline construction was completed in
February, with facilities additions completed in the fall.

SHARE PRICE AND DIVIDENDS

Although Enbridge has provided superior returns to share-
holders over the last five years, our share price performance
in 1999 was disappointing.

We believe that the decline we experienced in 1999 was not
a reflection of a change in business fundamentals, but rather
general market conditions. Although we don’t believe that
the current price reflects full value for our shares, we will con-
tinue to focus our attention on factors within our control
and on delivering profitable growth for our shareholders. Cer-
tainly senior management at Enbridge is convinced of the
continued fundamental strength of the Company and of our
prospects for growth — that is why senior management, and
many others in the Company, have shown their commitment
by continuing to acquire shares.

Conditions in the equity markets and circumstances related
to some of our peers also resulted in some erroneous con-
cerns regarding the dividend. Since 1995, Enbridge has
increased its quarterly dividend by an average of 5% each year.
These increases were based entirely on the level and quality
of earnings growth and not because of reduced opportuni-
ties to reinvest capital at attractive rates of return. During
this period, our payout has declined from 87% in 1995 to 63%
last year, which provides substantial support for the current
dividend. The Company has shown a commitment to further
increase dividends for shareholders as the last four years have
demonstrated. Based on our positive outlook for earnings
growth, we see no reason why this trend should not continue.

THE ENERGY BRIDGE

Last year was our first full year operating as Enbridge, one
Company with one name and one vision. We have had con-
siderable success in establishing this new brand, and we are
using the roots of our name — energy and bridge — as this
year’s annual report theme.

It’s appropriate because that is how we see ourselves — as a
bridge to our various stakeholders. We are an energy bridge
— the premier provider of energy delivery and services, to
seamlessly link our customers to sources of supply. We are
also a bridge from the financial capital invested by our share-
holders to the physical infrastructure required to meet our
customers’ energy needs and generate a return on investment.

A key link in all of our bridges is, of course, our employees,
and we thank them for their contributions during the past
year. It was a year of change and new challenges for many,
as we unbundled energy services and established the
shared services organization. We appreciate the special
effort and commitment that took. Special thanks, too, to all
those employees who worked so hard to prepare for Year
2000, and the more than 600 employees who participated
in the year end rollover to ensure a smooth, uneventful tran-
sition to 2000.

In 1999, we strengthened our bridges to and for our cus-
tomers, our shareholders, and the communities where we
operate. In 2000 and beyond, we will strengthen our exist-
ing bridges and continue to establish new ones for the
Enbridge of the future.

On behalf of the Board of Directors:

D.J. Taylor
Chairman of the
Board of Directors

February 23, 2000

B.F. MacNeill
President & Chief
Executive Officer

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Answers to some frequently asked questions

Why did Enbridge’s share
price drop in 1999?

Enbridge’s common share price declined from $35.25 to $28.65 in 1999. Since Enbridge pays a healthy
dividend, the net decline in terms of total shareholder return (dividends plus change in share price) was
16%. Although we’re not satisfied with this result, Enbridge’s share price performed relatively well
compared with our peers.

We believe that the decline related to general market conditions rather than a change in investors’ views
toward Enbridge. First, 1999 saw a steady and substantial rise in interest rates, and the increase
continued into 2000. That’s not a good situation for stocks such as ours that are sensitive to interest
rates. Generally, as interest rates rise, dividend paying stocks and interest bearing securities like
bonds decline in price and the opposite occurs when interest rates decline.

In addition, there was an unprecedented flow of funds from investors into other industries that benefit from
strong economic conditions, such as the high-tech industry, and to participation in the demutualization of
the insurance business in Canada. Despite the downturn, the fundamentals of our business remain strong
and our outlook for growth continues to be positive.

What is Enbridge’s
position on dividends?

Dividend policy is a matter for Enbridge’s Board of Directors, and subject to its ongoing review. In general,
however, given that we are well positioned to continue the pattern of strong earnings established over
the last five years, the Company expects dividend growth to continue.

Are you still
interested in electric
power distribution?

You had unbundling
problems. Why, and when
will the problem be fixed?

The pace of privatization of Ontario’s Municipal Electric Utilities (MEUs) has been slower than expected.
We are working with MEUs to pursue partnerships, shared services and other relationships, but we
believe it will be several years before there are major investment opportunities. However, we continue
to be encouraged by the prospects for convergence of energy sources. Enbridge is well positioned to
achieve synergies by sharing services between gas and electric distribution systems serving the same
customer base. We recently established a dedicated corporate entity that will provide common services
to all Enbridge distribution and energy services companies in Central and Atlantic Canada. This entity
will maximize resources and leverage cost synergies across all of our business units, and could
potentially provide services for third party entities such as MEUs.

Despite extensive planning and preparation for the transfer of non-regulated energy products and services
from Enbridge Consumers Gas to Enbridge Services, we experienced some start-up problems. A
combination of factors, including record numbers of customer telephone calls, resulted in delays in
answering calls and in dispatching service personnel. As a result, we disappointed some long-time
Enbridge customers, but we moved quickly to resolve the problems. We added personnel, phone lines
and service capacity, and brought service levels back to Enbridge’s high standards. The support and trust
of our customers is very important to Enbridge, and regaining their confidence has a high priority.

Does Enbridge plan
to make a large
corporate acquisition?

Our focus is on the substantial growth potential that exists within our core businesses. We believe
that numerous opportunities exist for continued expansion of these core businesses, as we have
demonstrated by our success in the past, as well as for selective small-scale acquisitions, joint ventures
and investments. However, we also will continue to assess other investment opportunities that could
make economic sense for us and for our shareholders.

When used in this annual report, the words “believe,” “estimate,” “forecast,” “anticipate,” “expect,” “project” and similar expressions are intended to
identify forward looking statements, which include statements relating to pending and proposed projects. Such statements are subject to certain risks,
uncertainties and assumptions pertaining to operating performance, regulatory parameters, weather and economic conditions and, in the case of pending
and proposed projects, risks relating to design and construction, regulatory processes, obtaining financing and performance of other parties, including
partners, contractors and suppliers.

T H E E N E R G Y B R I D G E

Patrick D. Daniel
President & Chief Operating
Officer, Energy Delivery

“ENBRIDGE’S CORE ENERGY DELIVERY

BUSINESSES CONTRIBUTE DIRECTLY TO

GROWTH MOMENTUM. LAST YEAR WE

BROUGHT ON STREAM OVER $1.5 BILLION

OF NEW CRUDE OIL PIPELINE ASSETS TO

SERVE OUR PRODUCING AND REFINING

CUSTOMERS, AND $400 MILLION OF NEW

GAS DISTRIBUTION FACILITIES IN ONTARIO

TO SERVE 58,000 NEW CUSTOMERS. WE

ALSO CONTINUED TO INCREASE

INTERNATIONAL EARNINGS.”

The Athabasca Pipeline (above) was completed
in 1999 as were the SEP II and Terrace Phase I
(at right) expansions.

Operations Review

In 1999, Enbridge adopted a new business seg-
mentation that better reflects how the business is
managed. These segments include Liquids Pipelines,
Gas Distribution, International, Gas Pipelines and
New Business Development, and Energy Services.

LIQUIDS PIPELINES

The Liquids Pipelines segment is one of Enbridge’s
two core businesses. Through subsidiaries such as
Enbridge Pipelines Inc., Enbridge owns and operates
the world’s longest crude oil and natural gas liquids
pipeline system. The mainline pipeline consists of
the wholly owned Enbridge System in Canada and the
Lakehead System in the United States. Enbridge has
a 15.3% interest in the Lakehead System.

The combined system is the primary transporter of
crude oil from Canada to the United States, and
is the only pipeline that transports crude oil from
Western Canada to Eastern Canada, serving all of
the major refining centres in the province of Ontario
as well as the Great Lakes region of the United
States. In 1999, the system delivered an average
of 2.0 million barrels per day, and as a result of
recently completed expansion programs, has overall
capacity of approximately 2.2 million barrels per
day. The system consists of approximately 14 000
kilometres (8,700 miles) of mainline pipeline in
Canada and in the United States.

Highlights in 1999 included strengthening of the
existing energy transportation business and addition
to overall pipeline capacity through completion of a
number of expansions and extensions including:

(cid:2) The System Expansion Program Phase II which
increased system capacity by 100,000 barrels per day
in Canada and 170,000 barrels per day into Chicago.

(cid:2) Terrace Expansion Phase I which added 170,000
barrels per day of capacity for heavy and synthetic oils.

(cid:2) The Athabasca Pipeline which has a potential capac-
ity of 570,000 barrels per day to transport synthetic
and heavy oils from northern Alberta to the pipeline
hub at Hardisty, Alberta.

(cid:2) Line 9 which went into fully reversed flow in Sep-
tember 1999, enabling shippers to deliver up to
240,000 barrels per day of offshore crude from
Montreal to refineries in the Sarnia area.

(cid:2) The Toledo Pipeline which connects the Lakehead
system at Stockbridge, Michigan, to two refineries
in the Toledo, Ohio, area, with capacity in excess
of 80,000 barrels per day of heavy crude oil.

In addition to these projects which were completed
in 1999, Enbridge announced a proposal to con-
struct a pipeline in the southern United States to
transport offshore crude oil from the St. James,
Louisiana, pipeline hub to Houston area refiners.
Enbridge is discussing the proposal, called the Alli-
gator Pipeline, with potential shippers and is
seeking firm commitments before proceeding with
a specific project application.

Another significant achievement in 1999 was the
successful negotiation of a five-year extension to
the Incentive Tolling Agreement (ITA). Enbridge and
the Canadian Association of Petroleum Producers
announced extension of the ITA for the years 2000
through 2004 for the Canadian mainline liquids
pipeline system. As of year end 1999, the first ITA
had generated after tax savings of $66 million that
were shared by Enbridge and its customers. The
fundamentals of the extended agreement are con-
sistent with the original agreement, and confirm
that Enbridge and its customers will continue to
share in savings from cost reductions and pro-
ductivity gains.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Norman Wells

Zama

Fort McMurray

Edmonton

Hardisty

Casper

Salt Lake City

Montreal

Toronto

Chicago

Toledo

Patoka

Liquids Pipelines

Enbridge Pipelines Inc. and
Lakehead Pipe Line Partners, L.P.
Enbridge Pipelines (NW) Inc.
Enbridge Pipelines (Saskatchewan) Inc.
Enbridge Pipelines (North Dakota) Inc.
Enbridge Pipelines (Athabasca) Inc.
Enbridge Pipelines (Toledo) Inc.
Mustang Pipe Line Partners
Frontier Pipeline Company
Chicap Pipe Line Company

The Liquids Pipelines business segment also includes:

(cid:2) Enbridge Pipelines (NW) Inc. which transports crude
oil from Norman Wells, N.W.T., to Zama, Alberta.

(cid:2) A number of feeder pipeline systems which deliver
crude oil to the mainline system, including Enbridge
Pipelines (Saskatchewan) and Enbridge Pipelines
(North Dakota), formerly Producers and Portal
pipelines, respectively.

(cid:2) Investment in a number of strategic crude oil
pipelines in the United States, including a 44%
interest in the Frontier Pipeline; a 30% interest in
Mustang Pipe Line Partners; and a 23% interest
in the Chicap Pipe Line Company.

GAS DISTRIBUTION

Gas Distribution is Enbridge’s other core business.
It includes Enbridge Consumers Gas, Canada’s largest
natural gas distribution company; Enbridge’s inter-
est in natural gas distribution in Quebec, through
Noverco Inc.; and Enbridge Gas New Brunswick.

Enbridge Consumers Gas: The Consumers’ Gas
Company Ltd., which is wholly owned by Enbridge
Inc. and which operates under the name Enbridge
Consumers Gas, has been distributing natural gas
to customers for more than 150 years. Together with
its subsidiaries, Enbridge Consumers Gas delivered
402 billion cubic feet of natural gas in 1999 to
approximately 1.5 million residential, commercial,
industrial, and transportation service customers.

Enbridge Consumers Gas serves customers in central
and eastern Ontario. Its wholly owned subsidiary
Gazifère Inc. serves southwestern Quebec, and St.
Lawrence Gas Company, Inc. serves parts of north-
ern New York State. Another subsidiary, Niagara
Gas Transmission Limited, provides transmission
services to Enbridge Consumers Gas, Gazifère and
St. Lawrence Gas, and links southwestern Ontario
storage facilities with pipelines in Michigan.

In recent years, Enbridge Consumers Gas has
shown sustained growth, adding more than 50,000
customers per year. In 1999, the distribution
network expanded with a 7.3% increase in
approved rate base reflecting the addition of 12
new communities and a record 58,000 new cus-
tomers. The company also received regulatory
approval to implement Performance Based Regu-
lation, which is expected to benefit ratepayers
through guaranteed productivity benefits and con-
tinued delivery of high quality service, and also
benefit Enbridge Consumers Gas. The Company
will operate under a simplified regulatory process
and reward shareholders when there are cost
reductions and productivity gains.

For years, Enbridge Consumers Gas operated as
an integrated, regulated utility, delivering natural
gas to customers, supplying heating and related
appliances, and providing maintenance and other
services. However, the growing shift towards energy
deregulation has resulted in unbundling of ser-
vices, which involves the removal of ancillary
products and services from regulatory control,

Stephen J. Wuori
President, Enbridge
Pipelines Inc.

“THE LIQUIDS PIPELINES BUSINESS

SEGMENT IS WELL POSITIONED TO

DELIVER SOLID GROWTH. WE HAVE THE

ABILITY TO TRANSPORT INCREASING

VOLUMES OF CRUDE OIL TO KEY

MARKETS, AND TO OFFER SUPERIOR

TOLLS, TRANSIT TIMES AND OPERATING

FLEXIBILITY TO OUR CUSTOMERS.”

Rudy G. Riedl
President, Enbridge
Consumers Gas

“IN 1999, ENBRIDGE CONSUMERS GAS

RESTRUCTURED ITSELF TO BE BETTER

PREPARED FOR MORE COMPETITION IN THE

RAPIDLY CHANGING ENERGY MARKETPLACE.

IN 2000, MANAGEMENT AND EMPLOYEES

WILL FOCUS ON CONSOLIDATING OUR GAINS

AND IMPROVING THE QUALITY OF SERVICE

TO OUR CUSTOMERS.”

T H E E N E R G Y B R I D G E

Mel F. Belich
Senior Vice President, International
Development & Corporate Law;
Chairman, Enbridge International Inc.
and Chairman, Enbridge Technology Inc.

“ENBRIDGE INTERNATIONAL

DEVELOPS AND MANAGES THE

CORPORATION’S INTERNATIONAL

ENERGY OPPORTUNITIES, INCLUDING

THE CONSTRUCTION, OWNERSHIP AND

OPERATION OF LIQUIDS AND NATURAL

GAS PIPELINES, TERMINALS AND

STORAGE SYSTEMS AROUND THE

WORLD. ENBRIDGE TECHNOLOGY

COMPLEMENTS THAT EFFORT BY

PROVIDING SPECIALIZED CONSULTING

AND TRAINING EXPERTISE ON A

GLOBAL BASIS.”

Enbridge invested in AltaGas Services (at left), continued to
add customers for Enbridge Consumers Gas (above), and
operated Cornwall Electric (at right).

thereby eliminating the regulatory constraints that
hamper the market responsiveness and competi-
tiveness of those businesses. As of October 1,
1999, a separate and unregulated affiliate called
Enbridge Services Inc. began delivering the prod-
ucts and services that Enbridge Consumers Gas
had historically delivered. Enbridge Consumers
Gas remains regulated, and will still be responsi-
ble for the supply and distribution of natural gas to
its customers.

Noverco: Through its 32% interest in Noverco Inc.,
Enbridge participates in gas distribution and trans-
mission in Quebec and the northeastern United
States — Noverco has a 77% interest in Gaz Mét-
ropolitain and Company, Limited Partnership. Gaz
Métropolitain is Quebec’s major gas distributor. The
only other distribution company in the province is
Gazifère, which is an Enbridge company.

Enbridge Gas New Brunswick: Enbridge is a 63%
participant in Enbridge Gas New Brunswick, which
was awarded the franchise for natural gas distrib-
ution in New Brunswick in September 1999.
Enbridge Gas New Brunswick anticipates investing
approximately $300 million during the 20-year fran-
chise period to distribute gas to up to 23
communities. Natural gas service to the first New
Brunswick customers is planned to start in late
2000. The project is of strategic importance
because it provides Enbridge with a presence in
Atlantic Canada, which is becoming an important
new energy region in North America.

INTERNATIONAL

Enbridge’s international objective is to supplement
its North American business activities with invest-
ments in attractive foreign projects that utilize the
Company’s technical and operating expertise. An
example is the company’s investment in the
OCENSA pipeline in Colombia.

OCENSA: The Oleoducto Central South America
(OCENSA) crude oil pipeline was Enbridge’s first
international venture, entered into in 1994.
Enbridge has a 17.5% interest and acts as joint
operator of the pipeline, tankage and marine
loading system that transports 500,000 barrels
per day of crude oil from the Cusiana and Cupiagua
oilfields in the central interior of Colombia to the
Port of Coveñas on the Caribbean coast. Enbridge
earns a fixed rate of return on its OCENSA invest-
ment, plus operating and incentive fees.

Venezuela: In January 1999, Enbridge announced
that it had entered into an agreement to operate and
acquire, through a Venezuelan general partnership,
a 45% interest in the Jose Crude Oil Storage and
Ship Loading Terminal project in Venezuela. The ter-
minal, a new facility located within the Jose Industrial
Complex, a large petroleum and petrochemical facil-
ity, handles crude oil from Eastern Venezuelan fields
for loading onto tankers for export, and has initial
throughput capacity of approximately 800,000
barrels per day. The partnership began operating the
Jose facility in April 1999, and as of year end 1999,
the acquisition was subject only to the receipt of gov-
ernment permits.

Technology: Enbridge Technology Inc. provides crude
oil pipeline and natural gas distribution consulting
and training services. A highlight in 1999 was the
completion of a significant contract with PEMEX
Refining, a subsidiary of the national oil company
of Mexico, to provide conceptual design and advisory
services on the modernization of its national crude
oil and refined products pipeline system. Enbridge
Technology provides consulting and training services
around the world. Its global reach provides Enbridge
with an entry into a variety of countries to review and
investigate business opportunities, and offsets inter-
national business development costs with earnings
from consulting and technology projects.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Inuvik

Fort St. John

Edmonton

Ottawa

Montreal

Dawn

Toronto

Chicago

Gas Distribution

Enbridge Consumers Gas
Noverco Inc.
Enbridge Gas New Brunswick
Inuvik Gas Project

Gas Pipelines

Alliance Pipeline
Vector Pipeline

Gas Gathering and Processing

AltaGas Services

Electric Power Distribution

Cornwall Electric

GAS PIPELINES AND NEW
BUSINESS DEVELOPMENT

In just a few short years, Enbridge has developed
a significant presence in the natural gas trans-
mission business, primarily through its investment
in the Alliance and Vector pipelines. In 1999,
Enbridge also entered the midstream gas business
with a 40% investment in AltaGas Services Inc.

Gas Pipelines: The Alliance Pipeline is a new gas
transmission system being built from Fort St. John,
British Columbia, to Chicago, Illinois. Enbridge has
a 21.4% interest in the project. The pipeline began
construction in the first quarter of 1999 and as
of year end 1999 had completed 2 150 kilometres
(1,336 miles), or 72% of the mainline. The line is
scheduled to be in service in October 2000 and will
have the capacity to deliver approximately 1.3
billion cubic feet per day.

Enbridge is the sponsor of and has a 45% interest
in the Vector Pipeline, which will transport natural
gas from Chicago to Dawn, Ontario. At Chicago,
Vector will connect with the Alliance Pipeline and
other natural gas transmission systems, providing
a transportation link for Western Canadian and U.S.
sourced supplies. Vector construction began early
in 2000, and the line is projected to be in service
in October 2000. Initial capacity will be approxi-
mately 1 billion cubic feet per day.

Gas Gathering and Processing: Enbridge entered the
midstream natural gas business in 1999 by acquir-
ing a 40% interest in AltaGas Services Inc., a
publicly traded, Alberta-based company that since
1994 has acquired or constructed over $390

million in natural gas assets. These assets include
natural gas gathering and processing facilities,
ethane and natural gas liquids extraction plant pro-
cessing capacity, and ownership of AltaGas Utilities
Inc., a natural gas distribution company serving over
90 Alberta communities. Enbridge’s investment in
AltaGas represents the addition of an attractive new
growth platform which is complementary to other
Enbridge energy delivery businesses.

Inuvik Gas Project: Enbridge owns a 33 1/3% inter-
est in the Inuvik Gas Project, together with partners
AltaGas Services (a 40% owned affiliate) and the
Inuvialuit Petroleum Corporation. The project
involves a 50 kilometre (30 mile) gas pipeline and
a local distribution network to supply gas to the
town of Inuvik in the N.W.T. Though small, the
project is significant in that it involves the first
commercialization of Mackenzie Delta natural gas
reserves, and augments Enbridge’s experience
with construction of pipelines in permafrost con-
ditions. It also provides a successful model for
cooperation with local interests in the development
of northern energy delivery infrastructure.

Electric Power Distribution: The 1998 acquisition of
Cornwall Electric — an Enbridge Company, has pro-
vided Enbridge with experience in the electric power
business in anticipation of further Enbridge invest-
ments in and partnerships with Ontario Municipal
Electric Utilities. In addition, Enbridge has devel-
oped a strategic alliance with Hydro-Québec, one of
the principal shareholders of Noverco. This strate-
gic alliance could provide significant competitive
advantages with respect to future electric power dis-
tribution and cogeneration opportunities.

J. Richard Bird
Senior Vice President, Corporate
Planning & Development and
President, Enbridge Consumers
Energy Inc.

“A WHOLE NEW INFRASTRUCTURE

GROWTH SEGMENT HAS BEEN

SUCCESSFULLY LAUNCHED ON THE

STRENGTH OF TRANSFERABLE SKILLS

AND SYNERGIES PROVIDED BY OUR

CORE BUSINESSES. THIS SEGMENT,

CONSISTING OF INVESTMENTS IN

NATURAL GAS PIPELINES, GATHERING

AND PROCESSING, AND ELECTRIC

POWER DISTRIBUTION, IS ALREADY

CONTRIBUTING 10% OF ENBRIDGE’S

EARNINGS. STRONG POTENTIAL FOR

FURTHER GROWTH EXISTS INCLUDING

DEVELOPMENT OF ALASKA NORTH

SLOPE, MACKENZIE DELTA AND EAST

COAST GAS RESERVES; RATIONALIZATION

OF THE WESTERN CANADA GATHERING

AND PROCESSING INDUSTRY; AND

RESTRUCTURING OF THE ONTARIO

ELECTRIC INDUSTRY.”

T H E E N E R G Y B R I D G E

Enbridge Services sells retail energy products (at left) and
services appliances (above). Enbridge’s Pat Daniel launches
Action By Canadians (at right) as Federal Environment and
Natural Resources Ministers Anderson and Goodale listen.

ENERGY SERVICES

In 1997, using its extensive experience in Enbridge
Consumers Gas as a base, Enbridge began to
make a measured entry into the emerging world
of deregulated and unbundled energy services in
Canada and the United States. Effective October 1,
1999, ancillary assets from the gas distribution
utility were transferred into a fully unregulated retail
products and services business called Enbridge
Services Inc. Enbridge Services began delivering,
in the non-regulated home comfort marketplace,
those products and services that Enbridge Con-
sumers Gas had historically provided as part of
its regulated operations. That includes operating
the Enbridge Consumers Gas Appliance Stores,

which now are known as Enbridge Home Services
stores, and offering a complementary portfolio of
retail energy products and services such as the
sale and maintenance of heating and air condi-
tioning appliances and equipment, hearth products,
and financing for those appliances.

In Canada, Enbridge Services operates outlets in
Ontario and B.C. Retail energy service opportunities
also have been identified in the United States, where
governments are going through similar stages of
energy deregulation and unbundling. Enbridge (Penn-
sylvania) Inc. was established in 1998 to test the
potential for developing a retail energy services busi-
ness in the Philadelphia area as a first step to
expanding into other United States markets.

Stephen J.J. Letwin
President & Chief Operating
Officer, Energy Services

“ENBRIDGE SERVICES ENTERED 2000

WELL POSITIONED TO GROW OUR

UNREGULATED RETAIL ENERGY

SERVICES BUSINESS. WE HAVE AN

ENVIRONMENT, HEALTH AND SAFETY — AND THE CHALLENGE OF CLIMATE CHANGE

EXCELLENT MANAGEMENT TEAM

FOCUSED ON OPERATIONAL

EXCELLENCE. WE HAVE SIGNIFICANT

OPPORTUNITIES FOR GEOGRAPHIC

EXPANSION AND INCREASED MARKET

SHARE IN OUR CORE AREAS.”

Enbridge’s commitment to health, safety and envi-
ronmental stewardship extends from the Board of
Directors to employees in the field. The Company
uses a comprehensive system of policies, pro-
grams and procedures to promote a safe work
environment, identify and control hazards, and
promote the safety of all personnel.

Similarly, Enbridge management ensures the
Company is operating in an environmentally respon-
sible manner. In 1999, the Company continued to
monitor and audit facilities, remediate sites, and
integrate environmental planning into a variety of
North American and International projects.

nating role and is developing the foundation for the
Company’s role in the climate change challenge.

In 1999, Enbridge was instrumental in creating a
nation-wide greenhouse gas emissions reduction
program, Action By Canadians. The program pro-
motes voluntary action by individual Canadians,
and was launched by Pat Daniel, Enbridge Presi-
dent & Chief Operating Officer, Energy Delivery, and
Chairman of the Energy Council of Canada. The
ABC program is a partnership with the Energy
Council of Canada and its member organizations,
15 of which have provided funding for the program,
and the Government of Canada.

A key environmental focus in 1999 was climate
change. The need to implement an effective corpo-
rate framework to manage greenhouse gas
emissions against a background of continuing policy
uncertainty resulted in the establishment of the
Enbridge Climate Change Task Force in the fall of
1999. The task force has a planning and coordi-

Enbridge is also a participant in Canada’s Climate
Change Voluntary Challenge and Registry (VCR). In
1999, Enbridge Consumers Gas and Enbridge
Pipelines (Saskatchewan) received Gold Champion
Reporting Level awards from the VCR, and Enbridge
Pipelines received a Silver Champion Reporting
Level award.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Enbridge supports a variety of initiatives that strengthen the fabric of
the communities where we operate.

ENBRIDGE IN THE COMMUNITY

Enbridge’s Community Investment Program reflects
a core value — corporate social responsibility. We
support organizations that require financial and
human resources, knowledge and structural capac-
ity that in turn will ultimately strengthen and
sustain communities. The overall objective is to
help build communities while supporting those in
need. We focus our community investment on
health and social services, education, environ-
mental and civic initiatives.

In 1999, Enbridge invested approximately $3.0
million while expanding our involvement in some
very key community-building opportunities.

Health and Social Services: A focus for Enbridge
employees in 1999 was the emerging social issues
around homelessness, child hunger, youth and
domestic violence. Through our combined corporate
and employee led donations and fundraising
events, Enbridge raised approximately $1.6 million
in Canada and another $120,000 in the United
States for the United Way. Another key initiative was
the Enbridge Festival of Trees, a Christmas part-
nership with the Alberta Lung Association and
Southern Alberta Children’s Hospital which raised
over $200,000 for the Hospital. Enbridge Con-
sumers Gas was one of the founding sponsors of
Share the Warmth, a not-for-profit fund that assists
low-income families, seniors, chronically ill and dis-
abled persons who are unable to pay their energy
bills. Last year, the Company assisted Share the
Warmth to expand its services to all of the areas
serviced by Enbridge Consumers Gas.

Education: Support for education included the
funding of major literacy-related programs to help
raise community awareness of the issue and the
need for this fundamental learning skill. Also, post-
secondary scholarships in Corporate Environmental

Management and Environmental Regulatory Studies
were created to advance the exchange of knowl-
edge between industry and students who represent
future industry leadership.

Environment: Since its inception in 1991, our highly
acclaimed and effective Environmental Initiative
Program (EIP) has contributed to over 200 innov-
ative and collaborative community-based groups in
communities along our pipeline system. Our EIP
helps community groups implement their own envi-
ronmental programs, and helps inform people of
the importance of being engaged in conservation
efforts. Specific projects included funding for an
interpretive trail system in Norman Wells, N.W.T.,
and wetland conservation and rehabilitation pro-
grams in Cornwall, Ontario.

Civic: In Eastern Canada, the Enbridge Community
Event Services Team continued to provide barbecue
services, a popular hot air balloon program and
special event services for a variety of community
functions. In 1999, over 800 community events
were supported, attracting over one million people.
In Western Canada, Enbridge helped create a unique
program called Leadership Calgary, with a compa-
rable program in Edmonton and the potential for
programs in Toronto and Ottawa. The program
recruits and nurtures rising leaders from all sectors
of the community, then helps develop civic leader-
ship skills through workshops and practicums.

Enbridge is committed to embracing and nurtur-
ing the spirit of volunteerism with our employees
and in our communities and supports a grassroots,
employee-driven program called Volunteers In Part-
nership. This community outreach program engages
employees and their families in supporting chari-
table organizations as volunteers with a wide range
of community-building programs.

Bonnie D. DuPont
Senior Vice President, Human
Resources & Public Affairs

“A BRIDGE NEEDS STRONG

FOUNDATIONS. ONE OF ENBRIDGE’S

FOUNDATIONS IS OUR EMPLOYEES.

ANOTHER IS THE SUPPORT OF THE

PEOPLE AND COMMUNITIES IN AREAS

WHERE THE COMPANY OPERATES.”

T H E E N E R G Y B R I D G E

Management’s Discussion and Analysis

Derek P. Truswell
Senior Vice President &
Chief Financial Officer

OVERVIEW

The following indicators illustrate Enbridge Inc.’s progress in
achieving its growth objectives.

Return on Average Common Shareholders’ Equity
Earnings Applicable to Common Shareholders (millions of dollars)
Earnings per Common Share (dollars per share)
Dividends per Common Share (dollars per share)
Total Assets (billions of dollars)
Active Customers at Gas Utility (thousands)
Liquids Deliveries (thousands of barrels per day)

Represents average ROE for five year period

1999

1998

1997

1996

14.3%
287.9
1.91
1.195
9.2
1,466
2,023

13.8%
240.9
1.66
1.120
8.3
1,414
2,136

14.2%
217.3
1.58
1.060
6.7
1,362
2,083

15.0%
180.3
1.45
1.015
5.8
1,307
1,970

Compound
Annual
Growth

1995

13.2%
130.4
1.15
1.000
5.2
1,264
1,754

14.1% 1
21.9%
13.5%
4.6%
15.3%
3.8%
3.6%

(cid:2) Return on average common shareholders’ equity improved
to 14.3% in 1999, well above average regulated rates of
return in Canada.

(cid:2) The Corporation’s total assets have grown by an average
of 15% annually over the past four years while still main-
taining a strong and improving return on common equity.

(cid:2) Earnings applicable to common shareholders increased by
$47 million, or 20%, over 1998 resulting in a compound
earnings growth rate of almost 22% per annum over the
last four years. This improvement was achieved despite the
record warm winters experienced in the Corporation’s gas
distribution franchise areas over the past two years which
adversely affected earnings by $31 million in 1999 and
$40 million in 1998.

(cid:2) With earnings per common share of $1.91 in 1999, the
Corporation has achieved its double digit growth objective
since 1995.

(cid:2) While increasing its quarterly dividend payments for the
fourth consecutive year in 1999, the Corporation has
reduced its dividend payout ratio to 63% from 87% in 1995,
in line with its growth objectives.

(cid:2) Despite the significant decrease in average crude oil prices
in late 1998 and its impact on throughput levels during
1999, the Corporation’s liquids pipeline systems have
recorded a 4% compound annual growth rate in throughput
over the last four years.

(cid:2) Similarly the Corporation’s gas distribution utility customer
base in Ontario has maintained a growth rate of 4% per
annum since 1995.

(cid:2) Since the beginning of 1995, Enbridge has invested $5.2
billion in additions to property, plant and equipment, long
term investments and acquisitions of subsidiaries and joint
ventures. These investments have been facilitated by a
continued access to capital markets. Over the last five
years, Enbridge has raised $4.9 billion through debt and
equity offerings in Canada and the United States.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

“ENBRIDGE HAS TRANSFORMED

FROM A RATE REGULATED BUSINESS

INTO A DIVERSIFIED ENERGY DELIVERY

AND SERVICE PROVIDER IN NORTH

AMERICA AND INTERNATIONALLY,

WHILE MAINTAINING ITS RELATIVELY

LOW RISK PROFILE.”

Earnings Applicable to
Common Shareholders
(millions of dollars)

Return on Average
Common Shareholders’
Equity (%)

0
5
1

2
3
1

2
4
1

8
3
1

3
4
1

Financial Highlights

(Canadian dollars in millions; except per share amounts)

1999

1998

1997

9
7
8
2

9
0
4
2

3
7
1
2

3
0
8
1

4
0
3
1

FINANCIAL HIGHLIGHTS

The following should be read in conjunction with the Consoli-
dated Financial Statements included in this report. The
Consolidated Financial Statements have been prepared in
accordance with Canadian Generally Accepted Accounting Prin-
ciples (GAAP). The impacts of differences between Canadian
and US GAAP are disclosed in Note 18 to the Consolidated
Financial Statements.

Earnings Applicable to

Common Shareholders

Liquids Pipelines
Gas Distribution
International
Gas Pipelines and New

Business Development

Energy Services
Corporate
Preferred Securities Distributions
Preferred Share Dividends

Cash Provided from Operating Activities
Common Share Dividends
Per Share Amounts1

Earnings
Dividends

165.3
99.2
28.7

143.2
100.2
24.3

108.4
132.1
16.1

31.2
(2.5)
(22.1)
(5.0)
(6.9)

6.3
(6.2)
(26.9)
—
—

(2.4)
(7.5)
(29.4)
—
—

287.9

240.9

217.3

495.1
186.4

312.4
168.3

437.8
147.1

1.91
1.195

1.66
1.120

1.58
1.060

Per share amounts reflect amounts applicable to common shares only and prior year amounts
have been restated to reflect the two for one stock split that occurred on May 10, 1999.

T H E E N E R G Y B R I D G E

Earnings applicable to common shareholders increased $47.0
million over 1998. The improvement is principally the result of
the expansion of the liquids mainline system, completion of
the Athabasca pipeline project, increased investment in gas
pipeline systems and fees earned from operating the Jose Ter-
minal in Venezuela. These improvements were partially offset
by higher financing costs to support the growth initiatives
and the absence of an insurance settlement recorded in
1998. The Gas Distribution segment continued to be affected
by warmer than normal weather, resulting in earnings consis-
tent with the prior year.

The improvement in 1998 earnings over 1997 was primarily
a result of the pipeline system construction and expansions
within the Liquids Pipelines, Gas Pipelines and International
segments as well as a full year contribution from the strategic
investment in Noverco Inc. and the settlement of an insurance
claim outstanding since 1991. These gains were partially
offset by warmer weather and a lower allowed rate of return
within Gas Distribution operations.

Increases in cash provided from operating activities are the
product of improved pretax earnings and lower current income
tax expense, the latter resulting from high tax deductions asso-
ciated with recent capital additions. The funding of changes
in operating assets and liabilities was not as substantial in
1999 as the previous year due to the lower level of acquisi-
tions, asset additions and long term investments.

Common share dividends paid over the last three years reflect
both increases in the dividend rate and the number of common
shares outstanding. As a result of sustained growth in earn-
ings, quarterly dividends increased to $0.2725 per share in
the third quarter of 1997, to $0.2875 per share in the third
quarter of 1998 and to $0.3025 per share in the second
quarter of 1999, representing increases of 5.8%, 5.5% and
5.2%, respectively.

RESULTS OF OPERATIONS

In 1999, Enbridge adopted a new business unit segmentation
that reflects current management accountability for opera-
tions. The operating segments shown below represent
strategic business units that are established by senior man-
agement of the Corporation to facilitate achievement of the
Corporation’s long term growth objectives, to aid in resource
allocation decisions and to assess divisional performance.
These segments include Liquids Pipelines, Gas Distribution,
International, Gas Pipelines and New Business Development,
and Energy Services. The following discussion and analysis

provides information on each business unit’s results on both
a segmented and operating basis. The operating results are
based upon those presented in Note 2 to the Consolidated
Financial Statements.

Liquids Pipelines

The results of the Liquids Pipelines segment include contribu-
tions from three primary North American liquid hydrocarbon
pipeline systems: the Canadian portion of the main crude oil
pipeline (Enbridge System), the 15.3% owned portion located
in the United States (Lakehead System) held through a U.S.
Master Limited Partnership (Partnership) and a wholly owned
pipeline originating in the Northwest Territories (Enbridge (NW)
System). The segment also includes the Corporation’s inter-
ests in the wholly owned Enbridge (Athabasca) Pipeline and
other feeder pipelines located in Canada and the United States.

Segmented Results

Liquids Pipelines

(Canadian dollars in millions)

Enbridge System
Lakehead System
Enbridge (NW) System
Enbridge (Athabasca) System
Feeder pipelines and other

1999

1998

1997

97.9
18.9
11.1
23.9
13.5

81.7
25.9
11.0
13.5
11.1

68.3
16.0
12.6
—
11.5

Earnings

165.3

143.2

108.4

Enbridge System

The increase in Enbridge System earnings over the three year
period is attributable to system expansions as well as sus-
tained achievements under incentive tolling. The second
phase of the System Expansion Program (SEP II) was com-
pleted in early 1999, while major portions of the Terrace
Expansion Project were put into service during 1999. The
1998 results included a $4 million gain on the resolution of
an insurance claim.

Under the Incentive Tolling Agreement (ITA) entered into in
1995, higher earnings are achieved by maximizing system
utilization and increasing operating efficiency, unlike traditional
cost based regulation where earnings are based on the level
of capital investment. Under the agreement, earnings in excess
of pre-determined thresholds are shared between the Corpo-
ration and its customers. In 1999, after tax cost savings
amounted to $17.7 million, providing a net benefit of $9.5
million to the Corporation (1998 – $9.0 million, 1997 – $9.3
million) and $8.2 million to industry (1998 – $7.7 million,

Incentive Tolling
Agreement Cost
Performance Savings
(after tax, millions of dollars)

7
7
1

3
7
1

7
6
1

Deliveries
(thousands of
barrels per day)

6
3
1
2

3
8
0
2

3
2
0
2

0
7
9
1

4
5
7
1

1
8

2
6

Shipper
Share

Enbridge
Share

2.5
3.4
8.0
7.7

8.2

3.7
4.7
9.3
9.0

9.5

1995
1996
1997
1998

1999

Total

6.2
8.1
17.3
16.7

17.7

1997 – $8.0 million). Since inception of the ITA in 1995, after
tax benefits of $66.0 million have been shared approximately
55% and 45% by the Corporation and industry, respectively.

Low crude oil prices in late 1998 and early 1999 resulted in
reduced throughput in 1999 on both the Canadian and U.S.
systems, however, Enbridge System earnings were not mate-
rially affected due to throughput protections incorporated in
the ITA.

Lakehead System

The Lakehead System also experienced significant through-
put reductions as a result of low crude prices. Crude oil
deliveries averaged 1,369,000 barrels per day in 1999 down
from the record 1,562,000 barrels in 1998, representing a
12% decline. Enbridge’s earnings were not materially affected
due to its level of ownership in the Lakehead System.

Partially offsetting the reduced equity income from the Part-
nership were greater incentive allocations to Enbridge, as
General Partner, due to achieving higher distribution levels to
unitholders of the Partnership.

In 1998, Lakehead System earnings included a $6 million gain
related to the settlement of an outstanding insurance claim,
which, coupled with higher incentive allocations resulted in
earnings improvements over 1997.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

By Product Type 1

Light Crude Oil
Medium and Heavy

Crude Oil

Refined Products and
Natural Gas Liquids

By Destination 1

Prairies
United States
Eastern Canada

1999

1998

1,036

1,089

774

833

213

214

2,023

2,136

447
1,028
548

2,023

459
1,105
572

2,136

99
97
95
1 Includes deliveries by the 15.3%

owned Lakehead System

Enbridge (NW) System

Through an agreement with the main shipper on the system,
Enbridge (NW) returns are the product of a deemed equity ratio
of 55% and the National Energy Board (NEB) prescribed mul-
tipipeline rate of return on equity. Over the last three years
Enbridge (NW) System earnings have been affected by a
declining rate base and reductions in the allowed rate of return
on equity to 9.58% in 1999 from 10.21% in 1998 and 10.67%
in 1997. Earnings have been modestly enhanced by incen-
tive cost savings.

Enbridge (Athabasca) System

This system delivers synthetic crude oil from the oil sands near
Fort McMurray, Alberta, to Hardisty, Alberta, where it joins into the
Enbridge and other pipeline systems. Contributions from this
system reflect the commencement of operations in April 1999
as well as the recording of Allowance for Equity Funds used
During Construction (AEDC) in 1998 and early 1999. The primary
shipper has entered into a long term contract with Enbridge, com-
mitting annual volumes at specified tolls over a thirty year period.
The result of these arrangements is similar in substance to a tra-
ditional cost of service tolling methodology and yields a return
equal to the NEB’s multipipeline rate in effect at the time of the
agreement. Accordingly, Enbridge recognizes earnings from this
system on a cost of service basis, with any difference between
recorded revenue and actual cash tolls reflected as a deferred

T H E E N E R G Y B R I D G E

transportation revenue charge. Any deferred amounts will be
recovered over the remaining years of the contract.

Feeder Pipelines and Other

Earnings from the feeder pipeline systems which connect with
the main pipeline system have remained stable over the three
year period, despite a growing contribution from the 44%
owned Frontier Pipeline which transports crude oil from
Casper, Wyoming, to Salt Lake City, Utah.

Operating Results

Liquids Pipelines

(Canadian dollars in millions)

Operating Revenue
Power Costs
Operating and Administrative Expenses
Depreciation

Operating Income
Investment and Other Income
Interest Expense

Earnings Before Income Taxes
Income Taxes

Earnings

1999

1998

1997

599.5
(67.5)
(168.1)
(115.5)

248.4
52.9
(88.4)

212.9
(47.6)

495.4
(82.3)
(152.4)
(87.0)

173.7
73.8
(62.0)

185.5
(42.3)

511.4
(83.3)
(147.1)
(85.8)

195.2
37.8
(66.6)

166.4
(58.0)

165.3

143.2

108.4

Operating revenue in 1999 increased over 1998 levels due to
the full year operating impact of SEP II as well as the com-
mencement of deliveries resulting from the completion of
Phase I of the Terrace expansion, the second quarter rever-
sal of Line 9 and commissioning of the Athabasca Pipeline.
Although there was lower throughput through the mainline
system during the year, revenues are effectively volume neutral
in that under the ITA revenues associated with such volumet-
ric shortfalls will be recovered in the following year through
higher tolls. 1998 revenues were lower than 1997 due to
the impact of prior years’ income tax recoveries refunded to
the shippers through lower tolls. Also contributing to the
decline in 1998 was a reduced rate of return and lower rate
base on the Enbridge (NW) System.

Despite pipeline expansions and project completions, more
efficient power usage on the various lines as well as lower
throughput in 1999 resulted in a reduction in power costs.
Increases in other operating and administrative expenses, par-
ticularly in 1999, are a result of higher activity levels
associated with new pipelines, Year 2000 remediation costs
and general inflation. Depreciation expense has also
increased reflecting system expansions and additions.

Investment and other income reflects AEDC as well as equity
earnings from the Partnership and U.S. feeder pipelines. The

higher level in 1998 is attributable to the level of construction
activity and a pretax $16 million gain on the settlement of an
insurance claim outstanding since 1991.

Interest expense increased in 1999 as a result of the com-
missioning of various pipeline expansions and additions. In
1998, during the construction phase, related interest expense
was capitalized as part of the cost of construction.

Income tax expense as a percentage of pretax earnings was
22.3%, 22.8%, and 34.9% for each of 1999, 1998 and 1997,
respectively. Generally these rates are lower than the expected
Canadian statutory rates as AEDC and equity earnings from
investments are non taxable items. Additionally, the use of
flow through tax accounting under which only current tax
expense is recorded can result in lower effective tax rates, par-
ticularly during periods of expansion when current tax
deduction levels are high.

Gas Distribution

The Gas Distribution segment includes Enbridge Consumers
Gas and related utilities as well as the Corporation’s 32%
interest in Noverco acquired in mid 1997 and the new fran-
chise awarded to Enbridge Gas New Brunswick in September
1999. The combined segmented and operating results for this
division are shown below:

Combined Segmented and Operating Results

Gas Distribution

(Canadian dollars in millions)

Enbridge Consumers Gas and
Related Utilities

Gas Sales
Gas Costs

Gas Sales Margin
Transportation Revenue

Net Gas Distribution Revenue
Other Revenue

Net Revenue
Operating and Administrative Expenses
Depreciation
Other Income
Interest Expense
Income Taxes

Noverco

Earnings

1999

1998

1997

1,368.5 1,411.5 1,763.4
(860.4) (1,035.9)
(897.5)

471.0
224.7

695.7
272.8

968.5
(390.0)
(238.1)
19.2
(184.4)
(93.6)

81.6
17.6

99.2

551.1
130.5

681.6
242.1

923.7
(363.9)
(215.0)
7.7
(176.5)
(93.5)

82.5
17.7

727.5
25.9

753.4
210.9

964.3
(370.7)
(185.8)
4.6
(164.1)
(123.1)

125.2
6.9

100.2

132.1

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Enbridge Consumers Gas
Approved Rate Base
(millions of dollars)

3
8
2
3

9
5
0
3

*
6
0
8
2

1
3
8
2

2
0
6
2

Enbridge Consumers Gas
Approved Return on
Common Equity (%)

5
7
8
1
1

5
1
1

3
0
1

3
7
9

1
5
9

96
00
98
* After unbundling of assets in 1999

Enbridge Consumers Gas
Degree Day Deficiency
(degrees Celsius)

9
0
2
4

8
5
0
4

1
1
0
4

3
0
0
4

9
7
0
4

2
5
3
3

0
6
0
4

0
6
4
3

97
Forecast

99
Actual

Enbridge Consumers Gas

Enbridge Consumers Gas is a rate of return regulated natural
gas distribution utility serving approximately 1.5 million cus-
tomers in central and eastern Ontario. The Ontario Energy
Board (OEB) sets rates based upon a deemed capital struc-
ture, an allowed rate of return on common equity, an approved
rate base and costs expected to be incurred by the utility
assuming normal weather. As customers are billed on an actual
volume basis, the utility’s ability to recover the allowed rate of
return depends upon achieving the forecast distribution
volumes under “normal weather” conditions. Other differences
in realized returns may result from variances between OEB
approved and actual capital expenditures, operating expenses,
interest expense, and income taxes.

Enbridge Consumers Gas’ 1999 earnings were consistent with
1998, both years significantly below 1997 results. In the past
two years the utility’s franchise area experienced significantly
warmer than normal weather, resulting in lower than expected
sendout volumes. Degree days 1, which represent a measure of
coldness in the franchise area, were 3,460 in 1999, 15% lower
than the expected 4,060. Similarly, in 1998, degree days were
3,352 or 18% lower than the expected 4,079. Actual degree days
of 4,011 in 1997 approximated the normal expected level.

1 Degree day deficiency is a measure of coldness. It is calculated by
accumulating for each day in the fiscal period the total number of degrees
by which the daily mean temperature fell below 18 degrees Celsius. The
figures given are those accumulated in the Toronto area.

The Corporation estimates that the significantly warmer than
normal weather resulted in a reduction of earnings of approx-
imately $31 million in 1999 and $40 million in 1998. In
response, in each year, the Corporation implemented a variety
of cost reduction initiatives, operational efficiencies and other
corporate actions across the Enbridge group of companies
to mitigate a large portion of the warm weather impact on con-
solidated results.

Since 1998, the utility’s annual change in allowed rate of return
has been based upon the forecast change in yield on Cana-
dian Government long term bonds. Reflecting the general year
over year reduction in Canadian interest rates in both 1998
and 1999, the allowed rate of return on common equity has
also been in decline. For the 1999 fiscal year, Enbridge Con-
sumers Gas’ allowed rate of return was 9.51% (1998 – 10.3%;
1997 – 11.5%) on a deemed 35% equity component of a
rate base of $3,283 million (1998 – $3,059 million; 1997 –
$2,831 million). The impact of these reductions in the allowed
rate of return has partially been offset by rate base growth.

The increase in rate base over the last three years reflects the
continued popularity of natural gas among homeowners and
builders, due to its relative price advantage and environmen-
tal benefits over other forms of energy. Enbridge Consumers
Gas has increased its active customer base by approximately
159,000 customers since the beginning of 1997, including
approximately 52,000 in 1999. The actual number of new con-
nections to the system in 1999 was approximately 58,000.

T H E E N E R G Y B R I D G E

Combined Gas Utilities
Volume of Gas Distributed
(billions of cubic feet)

9
2
4

8
2
4

1
9
3

7
9
3

2
0
4

Combined Gas Utilities
Number of Active
Customers (thousands)

6
6
4
1

4
1
4
1

2
6
3
1

7
0
3
1

4
6
2
1

The impact of recent weather patterns has been reflected in
net gas distribution revenue with 1999 showing a marginal
improvement over 1998 due to slightly colder weather, but a
significant decline from 1997’s normal weather. Gas sales rep-
resent revenue earned for commodity cost and delivery directly
to the customer. The decline in 1999 and 1998 is attributable
to both lower volumes due to weather and a shift in customer
demand for transportation service only. Partially offsetting
these reductions were increasing gas prices, which are passed
directly to customers. Transportation revenue represents
amounts earned from third party marketers using the utility’s
facilities to deliver direct-sell natural gas to customers. The
shift between these types of services does not impact net gas
distribution revenue as the difference equals the cost of gas
purchased which is passed on to the customer. Combined gas
sale and transportation service sendout volumes for the last
three years amounted to 402 billion cubic feet (bcf), 397 bcf
and 428 bcf in 1999, 1998 and 1997, respectively.

The year over year increase in other revenue is due to con-
tinued growth in ancillary programs (rentals, merchandising,
extended service products, merchandise finance plan, natural
gas vehicles, and agent billing collection).

Operating and administrative expenses include costs for the
utility and ancillary programs. The increase in 1999 is due to

higher costs associated with serving an expanding customer
base, growth in the ancillary programs, branding costs and
Year 2000 remediation costs, partly offset by continued cost
reduction initiatives. The decrease in 1998 expenses com-
pared with 1997 was mainly due to warmer weather, the
introduction of cost recovery and reduction measures, pro-
ductivity initiatives, and the absence of corporate reorganization
costs incurred in 1997.

Consistent with the growth in rate base and customer portfo-
lio size, depreciation expense has increased each year since
1997. Additional borrowings required to finance the growing
investment in property, plant and equipment have resulted in
increasing interest expense.

Income taxes, which are recorded on a flow through basis,
have declined in the past two years essentially as a result of
lower pretax earnings. Over the three year period the effective
tax rate has remained comparable.

Noverco

Noverco Inc. is a holding company whose principal asset is a
77% interest in Gaz Métropolitain and Company, Limited Part-
nership that is engaged in natural gas distribution in Quebec
and Vermont. Variations from normal weather have no effect
on Noverco’s earnings as the Quebec regulator holds utilities
weather neutral.

Equity earnings from Noverco reflect the Corporation’s 32%
equity interest adjusted for the effect of Noverco’s 10% reci-
procal shareholding in Enbridge and the amortization of the
excess of the purchase price paid over the underlying net book
value of the assets. However, a substantial portion of the earn-
ings from Noverco comprises dividends from the Corporation’s
$181.4 million investment in the preference shares of
Noverco. These shares entitle the Corporation to a cumulative
dividend based on the yield of 10 year Government of Canada
bonds plus 4.45%. The weighted average yield on the prefer-
ence shares, which is reset annually, was 10.0% and 10.6%
for 1999 and 1998, respectively.

International

International earnings represent income from the Corpora-
tion’s U.S. dollar denominated investment in the OCENSA
Pipeline in Colombia which commenced operations in 1998
and fees earned as operator of the Jose Terminal in Venezuela.
The Corporation also generates earnings from its international
technology and consulting services.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Segmented Results

International

(Canadian dollars in millions)

OCENSA Pipeline
Jose Terminal
Enbridge Technology
Business Development Costs

Earnings

1999

1998

1997

24.0
6.3
0.8
(2.4)

28.7

24.8
—
2.4
(2.9)

24.3

18.5
—
(0.1)
(2.3)

16.1

Enbridge earns a pre-established fixed rate of return on its
OCENSA investment and also acts as joint operator earning
operating and incentive fees. The increase in earnings com-
pared with 1997 reflects a higher average level of investment
due to completion of construction.

An agreement to acquire a 45% interest in the U.S. $385
million Jose Terminal in Venezuela, signed in early 1999 is
pending receipt of final assent from the Venezuelan Govern-
ment. For the intervening period, PDVSA Petroleos y Gas, S.A.,
the current owner of the Terminal, has engaged Enbridge and
its partners to operate the Terminal. During 1999, Enbridge
earned $6.3 million in net fees for operating the Terminal.

The 1999 decline in earnings from Enbridge Technology rep-
resents the completion of a consulting contract in Mexico.

Operating Results

International

(Canadian dollars in millions)

Operating Revenue
Expenses
Other Income
Income Tax (Expense) Recovery

Earnings

1999

1998

1997

24.0
(16.1)
23.6
(2.8)

16.0
(17.9)
26.3
(0.1)

6.6
(10.8)
19.4
0.9

28.7

24.3

16.1

Operating revenue is comprised primarily of consulting fees for the
automation and modernization of the Mexican national crude oil
and refined products pipeline system. This contract which com-
menced in 1998 was completed in 1999. Revenues in 1999 also
include fees derived as contract operator of the Jose Terminal.

Operating costs, include the cost of providing consulting ser-
vices in Mexico as well as new business development activities.
Included in other income are returns on the investment in the
OCENSA pipeline and certain related operating fees and incen-
tive distributions. OCENSA returns are received on a net of
tax basis, with no additional tax exigible at the Enbridge level.
Income tax expenses in 1999 relate to Venezuelan taxes on
fees earned from the Jose Terminal project.

Gas Pipelines and New Business Development

This segment’s results include equity income in respect of the
Corporation’s ownership interests in the Alliance Pipeline
Project (21.4%) and the Vector Pipeline Project (45%), both
of which are currently under construction with anticipated com-
missioning in late 2000. Alliance is a $5.0 billion project that
will transport natural gas from Fort St. John, British Columbia,
to Chicago, Illinois. Vector is a US $0.5 billion project that
will transport natural gas between Chicago and Dawn, Ontario.

The segment also includes the Corporation’s 40% equity inter-
est in AltaGas Services Inc., which provides natural gas
gathering, processing and related services as well as natural
gas transmission and distribution in Alberta.

Other new business initiatives include an electrical utility
serving the community of Cornwall, Ontario, and the 33 1/3%
owned Inuvik gas distribution utility located in Inuvik, N.W.T.

Segmented Results

Gas Pipelines and New
Business Development

(Canadian dollars in millions)

Alliance Pipeline Project
Vector Pipeline Project
AltaGas Services Inc.
Other New Business Initiatives
and Development Costs

Earnings

1999

1998

1997

27.7
5.5
2.0

(4.0)

31.2

8.6
1.4
—

(3.7)

6.3

0.7
—
—

(3.1)

(2.4)

Increases in earnings of Alliance and Vector are in line with
higher rate bases earning AEDC as construction progresses.
Earnings from AltaGas represent equity income since the third
quarter 1999 acquisition.

Operating Results

Gas Pipelines and New
Business Development

(Canadian dollars in millions)

Operating Revenue
Operating and Administrative Expenses
Depreciation
Other Income
Interest Expense
Income Tax Recovery

Earnings

1999

1998

1997

54.8
(56.7)
(5.1)
30.6
(0.3)
7.9

31.2

24.8
(28.9)
(2.6)
7.4
0.6
5.0

6.3

1.2
(7.7)
—
1.0
—
3.1

(2.4)

T H E E N E R G Y B R I D G E

Operating revenue, operating and administrative expenses and
depreciation expense are principally derived from Cornwall Elec-
tric, purchased in mid 1998, and other small new business
initiatives. Amounts in 1999 and 1998 have increased over prior
years commensurate with the timing of the inclusion of these
operations. Other income mainly represents equity earnings
from the Alliance, Vector and AltaGas investments. Income tax
recovery is principally related to initial operating losses on
various new business initiatives.

Energy Services

The Energy Services segment primarily reflects the Corpora-
tion’s initiative to provide integrated energy products and
services to retail and commercial customers in Ontario,
British Columbia and Philadelphia, Pennsylvania. Commenc-
ing in the fourth quarter of 1999, the ancillary programs
unbundled from Enbridge Consumers Gas have also been
included in this segment.

Operating Results

Energy Services

(Canadian dollars in millions)

Operating Revenue
Operating and Administrative Expenses
Depreciation
Interest Expense
Income Tax Recovery

Earnings

1999

1998

1997

143.4
(116.7)
(21.7)
(7.9)
0.4

21.4
(28.9)
(1.5)
(1.4)
4.2

0.6
(14.1)
(0.1)
—
6.1

(2.5)

(6.2)

(7.5)

In accordance with determinations of the OEB, on October 1,
1999, the Corporation separated and removed (unbundled) ancil-
lary business activities from the regulated operations of Enbridge
Consumers Gas into a wholly owned subsidiary of Enbridge in
the unregulated Energy Services segment. Major components of
this transaction were the water heater and furnace rental
program, merchandise financing operations, merchandise retail-
ing and related services. These operations are now reported on
a calendar year rather than the quarter lagged September 30
year end of Enbridge Consumers Gas. As a result, a one time
additional quarter of earnings (approximately $7 million) was
included in the transition year of 1999 for these operations.

In anticipation of unbundling, the Ontario operations contin-
ued the development of other retail and commercial service
and product offerings. This was accomplished through the
acquisition of four retail appliance stores and four service
providers in late 1998 as well as the development of a south-
ern Ontario franchise alliance of service providers under the
Enbridge brand.

Markets in which the acquired service providers operate include
the sales, installation and support for heating, ventilation and
air conditioning products, fireplaces, and appliances as well as
plumbing and electrical services. Historically, these markets
have been characterized by numerous small regional operators;
however, in recent years several aggregators have been acquir-
ing these operators to capitalize on synergies and brand loyalty.
Despite the high competition for potential acquisitions in its fran-
chise area, Enbridge believes it is prudent to take a measured
approach and has consistently applied its economic criteria,
which has resulted in slower than anticipated expansion of
operations. Management believes that, in the longer term, this
measured approach will translate into better economic returns.

Corporate and Other

The net cost for Corporate and Other items includes activi-
ties such as general corporate investments and costs
associated with financing non regulated activities. These costs
can be summarized as follows:

Corporate and Other

(Canadian dollars in millions)

Operating and Administrative Expenses
Depreciation
Investment and Other Income
Interest Expense

Loss Before Undernoted
Income Tax Recovery

Loss
Preferred Securities Distributions
Preferred Share Dividends

1999

1998

1997

(12.5)
(3.1)
44.8
(99.5)

(70.3)
48.2

(22.1)
(5.0)
(6.9)

(5.5)
(2.7)
23.5
(73.6)

(58.3)
31.4

(26.9)
—
—

(5.3)
(2.2)
6.8
(45.4)

(46.1)
16.7

(29.4)
—
—

Net Cost

(34.0)

(26.9)

(29.4)

Operating and administrative expenses increased in 1999,
reflecting centralization of certain business activities and
general corporate costs such as branding the Enbridge name
and Year 2000 remediation.

The increase in investment and other income in 1999 reflects
investment income from higher average cash balances and an
$18.2 million ($11.5 million after tax) dilution gain realized from
the Corporation’s investment in the U.S. pipeline operations. The
1998 investment and other income also included $13.5 million
($8.0 million after tax) of one time gains in 1998 associated with
the sale of non strategic real estate and recoveries under a
financing arrangement. In 1997, higher corporate provisions
commensurate with the Corporation’s significant growth initia-
tives effectively offset a dilution gain of $16.3 million recorded
on the Corporation’s investment in the U.S. Partnership.

The substantial rise in interest expense over the last three
years as well as preferred security distributions and preferred
share dividends accrued in 1999 reflect the impact of financ-
ing incurred to fund acquisitions and investments.

Capital
Expenditures,
Investments
and Acquisitions
(millions of dollars)

Income tax recoveries have increased over the three years in
line with the higher level of interest expense and other costs.

LIQUIDITY AND CAPITAL RESOURCES

The Corporation’s cash generated from operations combined
with continuous access to capital markets in Canada and
the United States plus approximately $2.0 billion in unutilized
credit facilities provide sufficient resources to finance growth
opportunities, debt repayments and dividend distributions. (For
a further description of the Corporation’s committed and
uncommitted credit facilities, reference should be made to Note
10 to the Consolidated Financial Statements.)

5
5
4
6
1

8
9
8
0
1

2
1
4
1
1

1999

1998

1997

Operating Activities

Summary of Cash Flows

(Canadian dollars in millions)

Cash Provided from Operating Activities
Earnings plus charges (credits)

not affecting cash
Changes in operating assets

626.9

490.4

486.9

and liabilities

(131.8)

(178.0)

(49.1)

Cash Used in Investing Activities
Investments and acquisitions
Capital expenditures
Changes in construction
payables and other

Cash Provided from Financing Activities

Debt issued (net)
Non controlling interest
preference shares

Preferred securities
Preferred shares
Common shares
Preferred share and

security distributions
Common share dividends

495.1

312.4

437.8

(257.1)
(357.5)
(783.7) (1,388.4)

(438.4)
(651.4)

(64.5)

55.1

30.9

(1,205.7) (1,590.4)

(1,058.9)

388.8

1,178.6

490.1

100.0
338.5
—
10.3

—
—
123.3
218.0

—
—
—
315.6

(11.9)
(186.4)

—
(168.3)

—
(147.1)

639.3

1,351.6

658.6

Increase (Decrease) in Cash

(71.3)

73.6

37.5

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

By Business
Segment

Liquids Pipelines
Gas Distribution
Gas Pipelines
Other

1999

380.7
365.4
341.8
53.3

1998

1,009.9
400.6
204.4
30.6

1997

221.6
748.8
38.8
80.6

1,141.2

1,645.5

1,089.8

Cash provided from operating activities increased in 1999 pri-
marily as a result of the commencement of operations of SEP II,
Terrace and Athabasca pipelines as well as lower current tax
expense, the latter resulting from high tax deductions associated
with recent capital additions. Funding requirements for operating
assets and liabilities were lower in 1999 due to the reduced level
of acquisitions, asset additions and long term investments.

Investing Activities

Cash used in investing activities in 1999 was $1.2 billion, 24%
lower than 1998 but 14% over 1997. This reflects the Cor-
poration’s strong growth in a changing North American energy
delivery and services market.

Expenditures related to system expansions in Liquids Pipelines
and Gas Pipelines, combined with ongoing improvements and
replacement of existing facilities in Gas Distribution, accounted
for the large increase in the level of capital investments over
the last three years.

In 1999, the Liquids Pipelines segment incurred capital
expenditures related to the construction of the Enbridge
(Athabasca) Pipeline ($160.3 million), Phase I of the Terrace
expansion ($119.4 million) and Line 9 Reversal ($18.0
million). In 1998, amounts were similarly spent on con-
struction of Athabasca ($266.7 million), Terrace ($481.1

T H E E N E R G Y B R I D G E

million) and the Canadian leg of SEP II ($58.8 million). Capital
expenditures in 1997 primarily related to SEP II and the first
phase of the System Expansion Program. Gas Distribution
capital expenditures remained relatively constant over each
of the three years averaging approximately $400 million per
year, representing the continuous growth in the customer
base. In 1999, other segments incurred a total of $43.8
million (1998 – $11.2 million; 1997 – $20.7 million) of
capital expenditures, principally in relation to the expansion
of Energy Services operations and infrastructure costs of new
business activities such as Cornwall Electric.

Expenditures on long term investments in 1999 reflected
investments in Alliance Pipeline Project of $138.0 million
(1998 – $105.4 million; 1997 – $30.5 million) and $24.6
million (1998 – $23.0 million) in the Vector Pipeline Project.
During 1999, the Corporation acquired an approximate 40%
interest in AltaGas for $163.8 million. In 1998 the Corpora-
tion invested U.S.$2.5 million (1997 – U.S.$38.7 million) in
the OCENSA Pipeline, acquired Cornwall Electric for $68
million and a 23% equity interest in the Chicap Pipe Line for
$33.3 million.

Included in 1997 long term investments was the purchase for
$332.4 million of $181.4 million of Noverco’s preference
shares and $151.0 million for 32% of its outstanding common
shares. In related and subsequent transactions, the Corpo-
ration has sold 15.5 million (after two for one split) of its
common shares to Noverco for total proceeds of $380.4
million. As a result, Noverco’s common share interest in the
Corporation was approximately 10% at December 31, 1999
and 1998 (1997 – 8%).

The construction related liabilities, incurred during the signif-
icant pipeline expansion period of 1997 through mid 1999,
were reduced at the completion of expansions and additions
accounting for the change in 1999.

Financing Activities

Over the three year period, the Corporation’s level of financing
activities also reflected its growth and investment strategies.

Funding sourced from debt or equity is determined primarily on
the basis of the capital structure appropriate for each business.
Certain of the Corporation’s regulated pipeline and gas distri-
bution operations issue long term debt to finance capital
additions, usually in the form of fixed rate debentures or
medium term notes. This external financing may be supple-

mented by debt or equity injections from the parent company.
Debt related to non regulated activities issued at the corporate
level has been incurred mainly to finance business acquisitions
and investments in subsidiaries, and is supplemented with the
issue of share capital. Funds for debt retirements are gener-
ated through cash provided from operating activities, as well
as through the issuance of replacement debt.

In 1999, Liquids Pipelines issued $275 million of medium
term notes (MTN) to finance system expansions and the
repayment of $85 million of MTNs, $40 million of debentures
and $48 million of variable rate financing. Gas Distribution
replaced $53 million in MTNs and matured debentures,
reduced its short term borrowings by $245 million, and
redeemed $100 million in preference shares. The preference
shares were replaced with the issuance of $100 million in new
redeemable preference shares. As these shares are not
redeemable at the option of the holder and only participate
in the earnings of Enbridge Consumers Gas, they have been
considered a non controlling (minority) interest ownership in
the Consolidated Financial Statements.

Also during 1999, the Corporation issued $200 million in
MTNs and $497 million in variable rate financing (net) in order
to finance non regulated and new corporate ventures. To opti-
mize the Corporation’s cost of capital and diversify the mix of
capital funding sources, the Corporation also issued $350
million in Preferred Securities. These Securities are unsecured
junior subordinated instruments that may be redeemed at the
Corporation’s option in whole or in part after five years. The
Corporation has the right to defer, subject to certain condi-
tions, distributions on the Securities for a period of up to 20
consecutive quarterly periods. Such deferred distribution
amounts are payable in cash, or at the option of the Corpo-
ration, from the proceeds on the sale of equity securities
delivered to the trustee of the Securities. As such, under Cana-
dian GAAP the securities are apportioned between their debt
and equity elements in the statement of financial position,
with the debt portion approximating the present value of the
49 year maturity amount. The Corporation has made cash pay-
ments with respect to distributions since the date of issuance.

In 1998, Liquids Pipelines issued $200 million of MTNs and
$73 million of variable rate financing (net) to finance expan-
sions of the pipeline system. Minor sinking fund repayments
of $22 million were also made in the year. Gas Distribution
replaced maturing long term obligations and sinking fund

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

payments of approximately $260 million and funded asset
growth with the issuance of $595 million of MTNs. To fund Cor-
porate investments, bridging of pipeline construction activities
and the maturing of $125 million of long term obligations,
the Corporation issued $400 million of MTNs and approxi-
mately $326 million of variable rate financing (net).

During 1997, Liquids Pipelines issued $50 million in MTNs
and an additional $62 million in variable rate financing (net)
to support capacity expansions of the pipeline system and
meet debt maturity obligations of $21 million. Consistent with
its large capital expenditure program and to replace matur-
ing long term obligations of approximately $70 million, Gas
Distribution issued $200 million of MTNs and effectively con-
verted (through the use of long term interest rate swaps)
approximately $100 million of short term borrowings into
medium term debt maturing in 2002. Finally, to fund Corpo-
rate investment activities, the Corporation issued $155 million
of variable rate financing and $100 million of MTNs.

As at December 31, 1999 (following a May 10, 1999 two for
one stock split), the number of common shares outstanding
had grown to 156.3 million shares from 135.0 million shares
(after split) at the beginning of 1997. In addition to the common
shares issued to Noverco in 1997 and 1998 ($380 million),
Enbridge has raised approximately $296 million of equity in the
three year period, including a $115 million public offering of
treasury common shares in October 1998. Also included in this
amount is a $125 million public offering of preferred shares
made in December 1998, $7.1 million in common shares
issued in conjunction with the AltaGas acquisition and contri-
butions of $38.4 million from the Corporation’s Dividend
Reinvestment and Share Purchase Plan.

Common share dividends paid over the past three years have
reflected a growing regular quarterly dividend on an increas-
ing number of common shares.

FINANCIAL RISK EXPOSURE AND MANAGEMENT

Earnings, cash flow and customers’ rates are subject to volatil-
ity stemming mainly from movements in the U.S./Canadian
dollar exchange rate, the price of natural gas, and interest
rates. In order to minimize these risks for both its ratepayers
and shareholders, the Corporation utilizes a variety of hedging
instruments to create an offsetting position to specific expo-
sures. All of these instruments are employed in connection
with an underlying asset, liability or anticipated transaction,

and are not used for speculative purposes. In implementing
its hedging programs, the Corporation has established formal
analysis and execution procedures, which require the prior
approval of either the Board of Directors or a committee of
senior management. Ongoing monitoring and senior man-
agement reporting procedures with respect to the hedging
programs are in place.

Foreign Exchange

In 1997, the Corporation established a hedging program to
eliminate 80% to 100% of the long term exposure relating to
U.S. dollar denominated investments. At year end 1999, the
Corporation had hedged future cash flows of approximately
U.S.$39 million per annum (1998 – U.S.$39 million; 1997 –
U.S.$30 million) as well as U.S.$100 million (1998 and 1997
– U.S.$100 million) on the redemption of the Corporation’s
investment in Colombia, thereby mitigating potential currency
exposures on anticipated cash flows from, and redemption of,
these U.S. dollar investments.

Natural Gas Prices

As allowed under the regulatory framework governing the Cor-
poration’s natural gas distribution operations, the Corporation
hedges the cost of a portion of its future natural gas supply
requirements. At December 31, 1999, approximately 10% of
its forecast fiscal 2000 system gas supply requirements, or
18 billion cubic feet, was hedged. As the cost of natural gas
ultimately flows through to customers in the form of regulated
gas costs, the customer realizes the results of this risk miti-
gation strategy. The OEB monitors the policies, procedures
and results of this hedging program.

Interest Costs

To hedge against the effect of future interest rate movements
on certain of its short term and long term borrowing require-
ments, the Corporation enters into various interest related
hedging instruments. As at December 31, 1999, the Corpora-
tion had effectively fixed interest rates on $696.3 million of
variable rate debt through floating to fixed interest rate swaps.

In anticipation of future debt issuances related to specific com-
mitted capital projects, the Corporation enters into financial
contracts to hedge a portion of the interest cost associated
with the anticipated issues.

T H E E N E R G Y B R I D G E

A detailed description and analysis of these transactions, includ-
ing the duration, carrying amounts and current valuations are
included in Note 13 to the Consolidated Financial Statements.
At December 31, 1999, no material credit risk exposure
existed as the Corporation enters into off balance sheet risk
management transactions only with creditworthy institutions
that possess strong investment grade ratings or where such
transactions are secured with approved forms of collateral.
Additionally, as the Corporation did not settle hedging instru-
ments in advance of the hedged transactions, there were no
gains or losses deferred in relation to any of the Corporation’s
off balance sheet hedges of anticipated transactions at
December 31, 1999 and 1998.

FUTURE PROSPECTS

When used in this section, the words “believe”, “estimate”, “fore-
cast”, “anticipate”, “expect”, “project” and similar expressions are
intended to identify forward looking statements. Such state-
ments are subject to certain risks, uncertainties and
assumptions pertaining to operating performance, regulatory
parameters, weather, economic conditions, etc. Should one or
more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual results may vary
significantly from those expected.

Enbridge expects continued earnings growth as a result of the
full year impact of 1999 pipeline expansions, investments and
acquisitions. These activities, along with the benefits of Per-
formance Based Regulation (PBR) in Ontario, the extension of
the Pipeline Incentive Tolling Agreement (ITA), and opportuni-
ties provided by the unbundling transaction and related shared
services concept in Eastern Canada, are expected to support
earnings growth patterns experienced since 1995. The 1999
recovery of crude oil prices could accelerate pipeline expan-
sion opportunities, further supporting earnings growth.
However, the continuation of warmer than normal weather,
as experienced by Enbridge Consumers Gas in the first fiscal
2000 quarter ended December 31, 1999, may impact Gas
Distribution results negatively, partially offsetting the expected
earnings growth discussed above.

The ongoing transformation of the Corporation into a diversi-
fied energy transporter and service provider in North America
and internationally, and entry into more non regulated busi-
nesses, is resulting in the risk profile of the Corporation

changing modestly. Entry into non regulated businesses
imposes greater economic exposure and requires more “at
risk” capital to be spent. This is managed by detailed analy-
sis and control processes with an expectation of higher returns
from these businesses. Costs related to these new activities
are deferred only if there is a reasonable certainty that the
outcome of the project will benefit future periods. Otherwise,
provisions are made against the project costs. In addition, pro-
visions are made for potential liabilities, if any, resulting from
claims against the Corporation arising in the normal course of
business including contested income tax reassessments. In
the opinion of management, exposures in excess of the pro-
visions made, if any, would not have a material effect on the
financial position of the Corporation.

Commodity Price Risk

Enbridge’s earnings are generally insulated from the impact of
fluctuations in crude oil and natural gas prices. The Liquids
Pipelines segment does not take ownership of the commodi-
ties transported and crude oil prices do not impact
transportation charges. A sustained increase or decline in
crude oil prices does have an impact, however, on exploration
and production activities in Western Canada, thereby ulti-
mately affecting the throughput levels on the pipeline systems.
With the downside volume protection available in Canada
under the ITA and the Corporation’s level of ownership in the
U.S. portion of the pipeline system, the Corporation’s sensi-
tivity to short term fluctuations in crude oil prices is
substantially reduced. Nevertheless, in the longer term, sus-
tained improved oil prices could generate pipeline expansion
opportunities. With the recent improvement in crude oil prices
as well as a number of industry milestones reached with oil
sands developments in the Province of Alberta, the outlook for
future growth and expansion opportunities remains positive.

Changes in gas prices do not have an effect on regulated
Gas Distribution earnings as commodity cost of gas is flowed
through to customers. Prolonged high gas prices, however,
could affect the economics of gas usage by customers in com-
parison with alternate energy sources. Despite the recent
increases in the price of natural gas, the Corporation expects
that natural gas will continue to hold a price advantage over
electricity in its franchise area and maintain its competitive
advantage against domestic fuel oil in the residential heating
market. In 1999, natural gas enjoyed, on average, a price

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

advantage on an equivalent annual volume basis of over 50%
against electricity and approximately 20% against domestic
fuel oil. It is expected that the current price advantage of
natural gas will continue in the foreseeable future. Addition-
ally, increasing natural gas prices will create further expansion
and investment opportunities for the Corporation in gas trans-
mission growth initiatives.

Regulatory Developments

Liquids Pipelines

In 1999, Enbridge and the Canadian Association of Petroleum
Producers agreed to an extension of the 1995 ITA for the
Canadian mainline liquids pipelines system. The new agree-
ment extends the current arrangement for another five year
term commencing in 2000. It preserves the significant exist-
ing benefits achieved for shippers and shareholders, and
includes new features which will provide additional benefits
for each. The extended agreement provides added incentives
to achieve further energy savings. It also provides a $90
million investment opportunity over the next three years at the
same time that shippers gain a toll surcredit. This results from
an agreement to refund deferred taxes previously collected by
Enbridge prior to 1992 and used to fund expansion of the
pipeline. Enbridge will add the investment to its mainline rate
base and will earn a rate of return on the equity portion at
the prescribed NEB multipipeline rate.

Gas Distribution

In December 1999, the OEB released its decision on Enbridge
Consumers Gas’ year 2000 Rate Application. The decision
included the approval of a rate of return of 9.73% (1999 –
9.51%) on a deemed 35% equity component of rate base of
$2,806 million (1999 – $3,283 million or $2,720 million
excluding the rental assets portion of the unbundled assets).

In the spring of 1998, in response to the changes occurring
in the industry, Enbridge Consumers Gas filed an application
with the OEB to separate and remove the Merchandise Sales
Program, Heating Parts Replacement Plan and the non regu-
lated Merchandise Finance Program, as well as certain aspects
of its non emergency service activities, from the existing oper-
ations of the regulated utility. On March 31, 1999, the OEB
released its decision with respect to terms and conditions
under which these businesses and activities could be under-
taken by the utility or transferred to another Enbridge affiliate.

In the March 1999 decision, the OEB denied the full recov-
ery of the unrecorded deferred income taxes of $168.0 million
related to the rental assets. The OEB determined that $50
million of the unrecorded deferred tax liabilities may be recov-
ered in future utility rates and a further $42 million in refunds
from Revenue Canada relating to a change in its assessing
practice can also be applied against the liability. Enbridge Con-
sumers Gas has filed an application for judicial review asking
the Divisional Court, Superior Court of Justice to set aside the
OEB’s order and that the matter of the deferred taxes be
referred back to the OEB for a rehearing. In the absence of a
full recovery, the disallowed balance of $76 million will be
charged to retained earnings upon the adoption of the new
income tax accounting standard.

On October 1, 1999, the Corporation transferred to the
Energy Services segment, not only the businesses described
above but the Rental Program assets as well. The net book
and fair market values of the net assets transferred were
approximately $737 million. Unbundling of these businesses
will leave Enbridge Consumers Gas as a core distribution
utility, ready to focus on operational excellence and able to
generate efficiencies which will benefit both shareholder and
ratepayers. The Energy Services segment will operate these
businesses independently outside of regulation, which will
allow these businesses to be run more efficiently. The over-
riding rationale for unbundling is that the introduction of
competitive markets will improve customer choice and
provide a broader opportunity for business to develop in the
province. Customers are expected to benefit from value
enhancing services.

Recent changes in regulation reflect a trend in Canada toward
incentive or performance based regulation (PBR). In April
1999, the OEB accepted Enbridge Consumers Gas’ proposed
targeted PBR plan for a three year term and has encouraged
Enbridge Consumers Gas to develop, in consultation with
stakeholders, an appropriate comprehensive PBR plan by
the end of this term. It is the OEB’s desire that this plan be
based upon either revenue cap or rate cap principles. A com-
prehensive plan of this nature would permit the Company to
set rates within certain limits and provide flexibility to adjust
prices to stay within the cap.

T H E E N E R G Y B R I D G E

Segmented Outlook

Liquids Pipelines

Enbridge expects continued earnings growth from its Liquids
Pipelines segment in 2000 as a result of the full year impact
of expansions as well as the gradual recovery of U.S. pipeline
operations to more normalized throughput levels.

Phase I of Terrace, Line 9 reversal and the Athabasca Pipeline
should provide greater earnings impact in 2000 as each of
these systems were only effective for part of 1999. The con-
tinuation of cost savings and the benefits of incentive
mechanisms under the extended ITA are also expected to
make a positive contribution to this segment’s earnings.

Gas Distribution

The earnings of Enbridge Consumers Gas will be reduced in
2000 by the impact of the intersegment shift of the unbun-
dled assets to the Energy Services division. However, the year
2000 utility earnings of Enbridge Consumers Gas will benefit
from an otherwise higher rate base as well as an increased
allowed rate of return. Furthermore, a return to normal weather
patterns in the franchise area and the anticipated benefits
to be realized under the new PBR enhance the earnings poten-
tial of this segment. These anticipated improvements could
be hampered by the continuation of warmer than normal
weather experienced in the quarter ended December 31, 1999
which represents the first fiscal quarter of Enbridge Con-
sumers Gas for the year 2000. The degree days in this quarter,
although 3% colder than the same quarter last year, were
approximately 10% lower than normal. The Corporation is
unable to predict whether these weather patterns are indica-
tive of the balance of fiscal 2000.

In that customers are billed on a volume basis, the Corpora-
tion’s ability to recover its total revenue requirement (i.e., the
cost of providing service) depends on achieving the forecast
distribution volumes established in the rate making process.
Weather during the year has a significant impact on sales to
and transportation of gas for customers in the higher margin
residential and commercial markets (which account for approx-
imately two-thirds of total distribution volumes) as the majority
of gas distributed to these markets is ultimately used for
space heating. Sales and transportation service to large
volume commercial and industrial customers are more sus-
ceptible to the prevailing economic conditions, including the
price of competitive energy sources for those customers who

have the ability to switch to alternate fuels. Customer addi-
tions are important to all market sectors as expansion adds
to the overall consumption of natural gas.

Earnings from Noverco are primarily derived from Enbridge’s
preferred share holdings that are anticipated to yield after
tax returns of approximately 10%.

Following the receipt of the natural gas distribution franchise
rights within the Province of New Brunswick in 1999, the Cor-
poration anticipates recording of AEDC amounts on ongoing
construction costs.

International

Earnings contribution from this segment will remain sensi-
tive to the timing of the completion of the acquisition of the
45% interest in the U.S.$385 million Venezuelan Jose Termi-
nal. For the intervening period, Enbridge and its partners will
continue operating the Terminal and earn operating fees. In
the absence of a successful closing of the acquisition, the
operating results of the International segment are expected
to remain relatively consistent in 2000.

Gas Pipelines and New Business Development

Construction on the 21.4% owned Alliance Pipeline Project com-
menced in 1999. The investment is accounted for using the
equity method. The pipeline component, which represents
approximately 88% of the expected capital costs, will contribute
significant earnings through AEDC earned on the increased
investment levels through to scheduled commissioning during
the fourth quarter of 2000. Equity earnings during the fourth
quarter and thereafter will reflect the pipeline’s contractually
established rate of return of approximately 11%. The Natural
Gas Liquids (NGLs) extraction plant component of the project
will not contribute to earnings until start up in the fourth quarter
of 2000. Based upon the current relationship between prices
for natural gas and NGLs, the plant would generate very attrac-
tive profit levels, but this relationship is not expected to remain
as favorable in the future.

Similarly, the Vector Pipeline Project commenced construction
in January 2000 and anticipates operations to commence in
late 2000. Again, increasing amounts of AEDC are expected to
be booked in 2000 in concert with this increasing investment.

The Alliance and Vector Pipelines have planned delivery capac-
ities of 1.3 billion and 1.0 billion cubic feet per day, respectively.
Enbridge has committed 105 million and 260 million cubic feet

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

per day of these capacities, respectively, of which a substan-
tial portion will be utilized to satisfy Enbridge Consumers Gas’
delivery requirements. Over the next two to four years, the
remaining capacities committed by Enbridge are expected to
be fully contracted out. However, during the initial period the
earnings from these projects may be reduced by toll discounts
and/or partially utilized capacity.

This segment’s earnings are also anticipated to benefit in
2000 from a full year earnings contribution from the 40%
investment in AltaGas Services Inc. acquired during the third
quarter of 1999.

Energy Services

With the October 1, 1999 transfer of the unbundled assets
from the rate regulated operations of Enbridge Consumers
Gas, this segment’s earnings are expected to increase sub-
stantially in 2000. Based on current performance levels, the
intersegment shift in earnings is expected to be approximately
$30 million.

The unbundled programs are now free to operate without reg-
ulatory constraints on rates of return that are applicable to
a gas distribution utility. To the extent that Energy Services
can continue to grow this business on a cost efficient basis
and utilize the existing market to further sell energy products
and services, increases in earnings are expected over the
next few years.

A key to this growth will be the retention of existing and the
capture of additional customers. System problems associated
with the transfer of responsibilities from the utility to this divi-
sion resulted in service disruptions. Although, these problems
have been rectified and Enbridge does not believe that long
term damage to its customer relationships has occurred, there
does exist a high level of competition for customer loyalty.

Consistent with this customer focus, Energy Services will be
re-examining its market segments to ensure that it is provid-
ing appropriate product offerings in its key target markets.

Capital and Investment Expenditures

The Corporation expects to incur capital and investment expen-
ditures of $800–$900 million in 2000. Approximately, half of
these expenditures will be incurred in its core operations par-
ticularly for the expanding customer base in Ontario. With the
exception of routine maintenance and enhancement programs

for the Liquids Pipelines division, no major expansions are cur-
rently anticipated. Nevertheless, the Corporation’s long term
outlook for the second and third phases of the Terrace Expan-
sion Program remains positive. The remainder of the anticipated
expenditures will occur as the construction of Alliance and Vector
Pipeline Projects continue. These anticipated levels of capital
expenditures do not reflect any funds required for new acquisi-
tions or joint venture investments. The Corporation’s cash
generated from operations in combination with its ability to main-
tain access to capital markets in Canada and the United States
along with its substantial unutilized credit facilities will provide
sufficient resources to finance the planned as well as any new
growth opportunities.

Year 2000 Issue

The Corporation entered the new millennium with no signifi-
cant Year 2000 related problems or service disruptions
reported by its business units or affiliated companies in North
America and internationally. The Corporation will continue mon-
itoring its energy distribution and transmission systems as
well as information technology and equipment for potential
date sensitive issues in 2000. To the end of December 31,
1999, the Corporation had incurred $33 million of operating
and $13 million of capital costs for Year 2000 remediation
and business continuity initiatives. As a result of fewer than
anticipated remediation issues, actual costs of the project
have been substantially below budgeted costs of $60 million.

In addition to having successfully rolled over the operations into
the new millennium, management expects longer term bene-
fits and efficiencies being realized from its Year 2000
Readiness Program. These benefits include substantial infor-
mation technology upgrades and the elimination of redundant
systems; completion of detailed and comprehensive listings of
hardware and software systems; and, enhancement of the Cor-
poration’s emergency response and disaster recovery plans.

Sensitivities

The following sensitivities are presented net of the effect of
Enbridge’s hedging activities. The Corporation estimates that
a 1% change in interest rates results in a $4 million change
in earnings and cash flow from operations. As a result of the
Corporation’s foreign exchange hedging program, there are no
material sensitivities to exchange rate fluctuations.

T H E E N E R G Y B R I D G E

By virtue of the regulatory environment in which the Gas Dis-
tribution segment operates, the Corporation’s natural gas
distribution operations have regulatory mechanisms in place
which provide for recovery of any increase in the price of
natural gas provided that gas procurement is undertaken on
a prudent basis, which the Corporation believes it consistently
does. Liquids Pipelines exposure to changes in crude oil and
natural gas liquid prices is limited to system utilization impacts
as the Corporation does not physically own the commodities
it transports.

Based upon results for the last two year period, a 20 degree
day deficiency has correlated to approximately $1 million in
earnings variance to the gas utility. However, due to the numer-
ous variables that impact earnings on a go forward basis,
this sensitivity may not be indicative of future impacts.

Accounting Pronouncements

Effective January 1, 2000, the Corporation is required to adopt
two new Canadian accounting standards. The new CICA Section
3465 — Income Taxes requires a focus on future income tax
assets and liabilities on a company’s balance sheet (liability
method) as opposed to a focus on the deferred tax provision
recorded in an entity’s income statement (deferral method). The
accounting standard permits rate regulated operations an
exemption from the application of the standard, meaning that
a significant portion of the Corporation’s operations will not be

required to adopt the new standard. These operations will
remain on the flow through method of accounting, which reflects
only actual income taxes payable as an expense. With respect
to business acquisitions, the Standard requires tax effects of
differences between the assigned and underlying tax values of
the identifiable net assets acquired to be recorded as future
income tax assets or liabilities and included in the allocation
of the cost of the purchase. Additionally, the tax effects of dif-
ferences between the carrying amount of an equity investment
and its tax basis must be recorded as a future income tax asset
or liability. Finally, Enbridge will also recognize the previously
unrecorded income tax liabilities associated with unbundling
and other deregulated assets. The combined impact of these
items will be an estimated net charge to Retained Earnings of
approximately $93 million effective January 1, 2000.

The new CICA Section 3461 — Employee Future Benefits
requires the Corporation to adopt an accrual method of
accounting for all employee future benefits, including pensions
and post employment medical and dental benefits. Given that
the Liquids Pipelines division is already required by regulators
to accrue for postretirement benefits in the United States and
pension costs in both Canada and the United States, and due
to the regulatory nature of Gas Distribution operations, the
Corporation anticipates that the implementation of this Stan-
dard will not have a material impact on its consolidated results
of operations and financial position.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Management’s Report

To the Shareholders of Enbridge Inc.
Management is responsible for the accompanying consolidated financial statements and all other information in this Annual
Report. The consolidated financial statements have been prepared in accordance with Canadian generally accepted
accounting principles and necessarily include amounts that reflect management’s judgement and best estimates. Financial
information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.

Management has established systems of internal control that provide reasonable assurance that assets are safeguarded
from loss or unauthorized use and produce reliable accounting records for the preparation of financial information. The
internal control system includes an internal audit function and an established code of business conduct.

The Board of Directors and its committees are responsible for all aspects related to governance of the Corporation. The Audit,
Finance & Risk Committee of the Board, composed of directors who are not officers or employees of the Corporation, has a
specific responsibility for ensuring that management fulfills its responsibilities for financial reporting and internal controls related
thereto. The Committee meets with management, internal auditors and independent auditors to review the consolidated financial
statements and the internal controls as they relate to financial reporting. The Audit, Finance & Risk Committee reports its findings
to the Board for its consideration in approving the consolidated financial statements for issuance to the shareholders.

PricewaterhouseCoopers LLP, appointed by the shareholders as the Corporation’s independent auditors, conducts an examination
of the consolidated financial statements in accordance with Canadian generally accepted auditing standards.

B.F. MacNeill
President & Chief Executive Officer

D.P. Truswell
Senior Vice President & Chief Financial Officer

Auditors’ Report

To the Shareholders of Enbridge Inc.
We have audited the consolidated statements of financial position of Enbridge Inc. as at December 31, 1999 and 1998 and
the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period
ended December 31, 1999. These financial statements are the responsibility of the Corporation’s management. Our responsibility
is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that
we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the
Corporation as at December 31, 1999 and 1998 and the results of its operations and cash flows for each of the years in the
three year period ended December 31, 1999 in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta, Canada
January 14, 2000

(PricewaterhouseCoopers LLP)
Chartered Accountants

T H E E N E R G Y B R I D G E

Consolidated Statement Of Earnings

(Canadian dollars in millions, except per share amounts)
Year ended December 31,

1999

1998

1997

Operating Revenue

Gas sales
Transportation
Energy services and other

Expenses

Gas costs
Operating and administrative
Depreciation

Operating Income
Investment and Other Income (Note 3)
Interest Expense (Note 4)

Earnings Before Undernoted
Income Taxes (Note 5)

Earnings
Preferred Security Distributions (Note 11)
Preferred Share Dividends (Note 11)

Earnings Applicable to Common Shareholders

Earnings Per Common Share (Note 11)

Consolidated Statement Of Retained Earnings

(Canadian dollars in millions, except per share amounts)
Year ended December 31,

Retained Earnings at Beginning of Year
Earnings Applicable to Common Shareholders
Preferred Share and Preferred Security Issue Costs (Note 11)
Common Share Dividends

Retained Earnings at End of Year

Dividends Per Common Share

The accompanying notes to the consolidated financial statements are an integral part of these statements.

1,374.2
820.3
493.2

2,687.7

903.1
821.6
383.8

1,416.1
624.8
300.8

2,341.7

865.0
675.0
309.0

2,108.5

1,849.0

579.2
188.7
(380.6)

387.3
(87.5)

299.8
(5.0)
(6.9)

287.9

1.91

492.7
156.4
(312.9)

336.2
(95.3)

240.9
–
–

240.9

1.66

1,763.9
537.3
218.8

2,520.0

1,036.4
638.4
274.0

1,948.8

571.2
76.5
(276.1)

371.6
(154.3)

217.3
–
–

217.3

1.58

1999

407.6
287.9
(6.0)
(186.4)

503.1

1.195

1998

336.7
240.9
(1.7)
(168.3)

407.6

1.120

1997

266.5
217.3
–
(147.1)

336.7

1.060

Consolidated Statement Of Cash Flows

(Canadian dollars in millions)
Year ended December 31,

Cash Provided from Operating Activities

Earnings
Charges (credits) not affecting cash:

Depreciation
Equity earnings in excess of cash distributions (Note 7)
Gain on long term investment dilution (Note 7)
Deferred income taxes (Note 5)
Other

Changes in operating assets and liabilities (Note 6)

Investing Activities

Long term investments (Note 7)
Acquisition of subsidiaries (Note 8)
Additions to property, plant and equipment
Changes in construction payable (Note 6)
Other

Financing Activities

Variable rate financing, net
Fixed rate financing, net (Note 10)
Non controlling interest preference shares (Note 10)
Preferred securities (Note 11)
Preferred shares (Note 11)
Common shares (Note 11)
Preferred security distributions (Note 11)
Preferred share dividends (Note 11)
Common share dividends

Increase (Decrease) in Cash
Cash at Beginning of Year

Cash at End of Year

The accompanying notes to the consolidated financial statements are an integral part of these statements.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

1999

1998

1997

299.8

240.9

217.3

383.8
(29.7)
(18.2)
5.5
(14.3)
(131.8)

495.1

(340.8)
(16.7)
(783.7)
(56.0)
(8.5)

309.0
(13.8)
(1.0)
(26.1)
(18.6)
(178.0)

312.4

(181.0)
(76.1)
(1,388.4)
61.9
(6.8)

274.0
(9.2)
(16.3)
(0.1)
21.2
(49.1)

437.8

(434.8)
(3.6)
(651.4)
36.2
(5.3)

(1,205.7)

(1,590.4)

(1,058.9)

204.3
184.5
100.0
338.5
–
10.3
(5.0)
(6.9)
(186.4)

639.3

(71.3)
124.9

53.6

349.0
829.6
–
–
123.3
218.0
–
–
(168.3)

1,351.6

73.6
51.3

124.9

130.6
359.5
–
–
–
315.6
–
–
(147.1)

658.6

37.5
13.8

51.3

T H E E N E R G Y B R I D G E

Consolidated Statement Of Financial Position

(Canadian dollars in millions)
December 31,

Assets
Current Assets

Cash
Accounts receivable and other
Gas in storage

Long Term Investments (Note 7)
Deferred Charges and Other
Property, Plant and Equipment, Net (Note 9)

Liabilities and Shareholders’ Equity
Current Liabilities

Short term borrowings
Accounts payable and other
Interest payable
Current portion of long term liabilities

Long Term Debt (Note 10)
Deferred Credits
Deferred Income Taxes (Note 5)
Non Controlling Interest Preference Shares (Note 10)
Commitments and Contingencies (Note 16)

Shareholders’ Equity

Share capital (Note 11)
Preferred securities
Preferred shares
Common shares

Issued – 1999 – 156,308,000 (1998 – 155,710,000)

Retained earnings
Foreign currency translation adjustment
Reciprocal shareholding (Note 7)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Approved by the Board:

(D.J. Taylor)
Director

(F.W. Fitzpatrick)
Director

1999

1998

53.6
678.5
375.1

1,107.2
1,051.6
278.7
6,770.7

9,208.2

155.4
494.6
86.1
174.4

910.5
5,284.8
157.8
254.5
100.0

124.9
611.3
357.8

1,094.0
676.9
212.1
6,364.2

8,347.2

400.4
540.9
87.9
257.5

1,286.7
4,502.3
230.4
266.4
–

6,707.6

6,285.8

341.1
125.0

–
125.0

1,677.2
503.1
(23.9)
(121.9)

2,500.6

9,208.2

1,659.8
407.6
(9.1)
(121.9)

2,061.4

8,347.2

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Notes To The 1999 Consolidated Financial Statements
(Canadian dollars in millions, except per share amounts)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Corporation’s primary business activities are the transportation and distribution of energy. These activities are
conducted through the Corporation’s five operating segments: Liquids Pipelines, Gas Distribution, International, Gas
Pipelines and New Business Development, and Energy Services.

The consolidated financial statements of the Corporation are prepared in accordance with Canadian generally accepted
accounting principles and conform in all material respects with the historical cost accounting standards of the International
Accounting Standards Committee.

The preparation of financial statements in conformity with generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related
disclosures. Actual results could differ from those estimates and assumptions; however, management believes that
such differences would not be material.

Basis of Presentation
The consolidated financial statements include the accounts of the Corporation, its subsidiaries and the proportionate
share of the accounts of its joint ventures. Investments in entities which are not subsidiaries or joint ventures, but over
which the Corporation exercises significant influence, are accounted for using the equity method. Other investments are
accounted for on the cost basis.

The Corporation’s Gas Distribution business is conducted primarily through a wholly owned subsidiary, The Consumers’
Gas Company Ltd. (Enbridge Consumers Gas). The Corporation consolidates the September 30 fiscal year results of
Enbridge Consumers Gas on a quarter lag basis, which reflects the results of Enbridge Consumers Gas operations in
accordance with its regulatory, tax and operating cycles. Accordingly, references to “December 31” reflect the financial
position of Enbridge Consumers Gas as at September 30, and references to the “year ended December 31” include the
results of Enbridge Consumers Gas for its fiscal year ended September 30.

Regulation
The Corporation’s primary business activities are subject to regulation by various authorities, including the National Energy
Board (NEB) for Canadian Liquids Pipelines and Gas Pipelines operations, the Federal Energy Regulatory Commission
(FERC) for U.S. Liquids Pipelines and Gas Pipelines operations, and the Ontario Energy Board (OEB) for the Gas Distribution
operations. These and other regulatory authorities exercise statutory authority over various matters such as construction,
rates and underlying accounting practices, and ratemaking agreements with shippers. In order to achieve proper matching
of revenues and expenses, the Corporation follows accounting practices prescribed by the regulators or stipulated in
approved ratemaking agreements. Accordingly, the timing of recognition of certain revenues and expenses in these
operations may differ from that otherwise expected under generally accepted accounting principles applicable to non
regulated operations.

Foreign Currency Translation
The functional currency of the Corporation’s foreign operations, except for certain financing and investing activities, is
the U.S. dollar. These operations are self sustaining and translated into Canadian dollars using the current rate method.
Assets and liabilities are translated into Canadian dollars at rates of exchange in effect at the date of the consolidated
statement of financial position. Revenue and expense items are translated at exchange rates prevailing during the year.
Gains and losses resulting from these translation adjustments are deferred as a separate component of shareholders’
equity until there is a realized reduction of the foreign investment.

The functional currency of the Corporation’s foreign financing and investing operations is the Canadian dollar. These
operations are integrated with those of the parent company and are translated into Canadian dollars using the temporal
method. Monetary assets and liabilities are translated into Canadian dollars at rates of exchange in effect at the date of
the consolidated statement of financial position. Non monetary assets and liabilities are translated at historical rates of
exchange. Income and expense items are translated at exchange rates prevailing during the year, except for items relating
to non monetary assets and liabilities which are translated at the applicable historical rates of exchange. Gains and losses
resulting from these translation adjustments are included in earnings.

T H E E N E R G Y B R I D G E

Revenue Recognition
Revenues are recorded when products have been delivered or services have been performed. The gas and liquids
transportation and gas distribution operations of the Corporation are subject to regulation by various authorities and,
accordingly, there are circumstances where revenues recognized do not match the cash tolls or the billed amounts. In
these situations, revenue is recognized in a manner that is consistent with the underlying rate design as mandated by
the regulatory authority or under the terms of enforceable committed long term delivery contracts.

Income Taxes
The Corporation recovers income tax expense based on the taxes payable method when prescribed by the regulators for
ratemaking purposes or when stipulated in ratemaking agreements. Under this method, no provision is made for
income taxes deferred as a result of timing differences in the recognition of revenues and expenses for income tax and
financial statement purposes. This method is followed for accounting purposes as there is reasonable expectation that
all such taxes will be recovered through rates when they become payable. In all other instances, the tax allocation method
of accounting is followed.

Cash
Cash includes short term and demand deposits which are valued at cost. The short term deposits are all highly marketable
securities with a maturity of three months or less when purchased and are held to maturity.

Gas in Storage
Supplies of natural gas are recorded in inventory at prices as approved by the OEB in the determination of customer sales
rates. The actual cost of gas purchased includes the effect of any natural gas price risk management activities. The
difference between the approved price and the actual cost of the gas purchased is deferred for future disposition as
approved by the OEB.

Deferred Charges
Deferred charges related to projects which may benefit future periods are capitalized and upon commercial viability are
amortized over the useful life of the initiative, or expensed upon abandonment of the project. Deferred financing charges
are amortized on the straight line basis over the life of the related debt. Unamortized financing charges related to
refinanced debt, together with the costs of issuing replacement debt, are deferred and amortized over the life of the
replacement issues.

Property, Plant and Equipment
Expenditures for system expansion and major renewals and betterments are capitalized; maintenance and repair costs
are expensed as incurred. Regulated operations follow the practice of capitalizing, at rates authorized by the regulatory
authorities, an allowance for interest during construction. When prescribed by the regulator, liquids and gas transportation
operations also capitalize an allowance for equity funds used during construction, at authorized rates.

Contributions in aid of construction of gas distribution and electrical utility assets are deducted from the cost of
acquiring property, plant and equipment, with subsequent depreciation calculated on the net cost.

Depreciation
Depreciation of property, plant and equipment is generally provided on the straight line basis over their estimated
service lives. When property, plant and equipment are retired or otherwise disposed of, the cost less net proceeds is
charged to accumulated depreciation. For unusual disposals, the gain or loss arising on disposition is included in earnings.

A provision for Gas Distribution future removal and site restoration costs is recorded against and recovered through
depreciation at rates approved by the OEB. Actual costs incurred are charged to accumulated depreciation. Similar
costs are not recovered through tolls for liquids and gas transportation pipeline activities as regulatory approval has not
been sought and the recovery method and timing have not been determined. No provision has been made for future
pipeline removal and site restoration costs since it is expected that these costs will be recovered through pipeline tolls.

Off Balance Sheet Financial Instruments
Gains and losses on financial instruments used to hedge the Corporation’s investments in self sustaining foreign
operations are deferred and included in the cumulative translation adjustment. Amounts received or paid under financial
instruments used to hedge cash flows from U.S. dollar denominated operations are recognized concurrently with the
hedged cash flows. Amounts received or paid under financial instruments used to hedge purchases of natural gas are

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

recognized as part of the cost of the underlying physical purchases. For other off balance sheet financial instruments,
amounts received or paid, including deferred gains and losses realized upon settlement, are recognized over the life of
the underlying hedged items.

Postretirement Benefits
The Corporation maintains both defined benefit and defined contribution pension plans. Pension costs and obligations
for the defined benefit pension plans are determined using the projected benefit method and are charged to earnings as
services are rendered, except in the Gas Distribution segment where contributions made to the plan are expensed as
pension costs, consistent with its ratemaking process. For the defined contribution plan, contributions made by the
Corporation are expensed as pension costs.

The Corporation also provides postretirement benefits other than pensions, including group health care and life insurance
benefits for eligible retirees, their spouses and qualified dependants. For Canadian operations, these costs are charged to
earnings as incurred. For U.S. operations, the cost of such benefits is accrued during the years the employees render service.

Comparative Amounts
Comparative amounts are reclassified to conform with the current year’s financial statement presentation.

2. SEGMENTED INFORMATION

The operating segments shown below represent strategic business units which are established by senior management
of the Corporation to facilitate the achievement of the Corporation’s long term growth objectives, to aid in resource allocation
decisions and to assess operational performance. In all material respects, the measurement basis for preparation of
segmented information is consistent with the significant accounting policies outlined in Note 1.

Liquids Pipelines
The Corporation’s main crude oil pipeline system is the primary transporter of Western Canadian crude oil production. The
system extends across the Canadian prairies to the major refining centres in the Great Lakes region of the United
States and continues into Ontario and Quebec. The Canadian portion of the system is owned and operated by a wholly
owned subsidiary; the U.S. portion is operated and 15.3% owned by a wholly owned U.S. subsidiary through a Master
Limited Partnership. The Corporation also owns feeder pipeline systems in North America through wholly owned
subsidiaries. As well, this segment reflects the operations of Enbridge (Athabasca) System which delivers synthetic
crude oil from the oil sands near Fort McMurray, Alberta, to Hardisty, Alberta.

Gas Distribution
The Gas Distribution segment consists largely of gas utility operations which serve 1.5 million residential, commercial,
industrial and other customers, primarily in central and eastern Ontario. Contributions from the Corporation’s strategic
investment in Noverco Inc. (Note 7) are also included.

International
This segment reflects the Corporation’s long term investment in a crude oil pipeline in Colombia for which the
Corporation also acts as an operator. The segment also includes operating fees earned from the operation of the Jose
Terminal in Venezuela.

Gas Pipelines and New Business Development
The Corporation’s investment in two natural gas transmission lines, Alliance Pipeline (21.4% owned), and Vector Pipelines
(45% owned and to be operated) are included in this segment, as are revenues and expenses associated with electricity
distribution and the Corporation’s 40% equity interest in AltaGas Services Inc. The segment also includes costs of
investigation, evaluation and development of new business development projects which are not included in the core business
of the other segments.

Energy Services
This segment includes the results of the Corporation’s retail appliance, fireplace and water heater operations as well as
mass market and commercial plumbing, heating, ventilation and air conditioning, appliance repair and electrician contractor
services which operate in both Canada and the United States. Petroleum marketing and related services are also included
in this segment.

T H E E N E R G Y B R I D G E

Operating Segments

Year ended December 31, 1999

Operating Revenue
Gas sales
Transportation
Energy services and other

Expenses

Gas costs
Operating and administrative
Depreciation

Operating Income (Loss)
Investment and Other Income
Interest Expense

Earnings (Loss) Before Income Taxes
Income Taxes

Earnings (Loss)

Additions to Property, Plant and Equipment

Year ended December 31, 1998

Operating Revenue
Gas sales
Transportation
Energy services and other

Expenses

Gas costs
Operating and administrative
Depreciation

Operating Income (Loss)
Investment and Other Income
Interest Expense

Earnings (Loss) Before Income Taxes
Income Taxes

Earnings (Loss)

Additions to Property, Plant and Equipment

Liquids
Pipelines

Gas

Distribution1 International

Gas
Pipelines

Energy
Services1

Corporate2 Consolidated

—
595.6
3.9

599.5

—
235.6
115.5

351.1

248.4
52.9
(88.4)

212.9
(47.6)

165.3

376.9

1,368.5
224.7
272.8

1,866.0

897.5
390.0
238.1

1,525.6

340.4
36.8
(184.4)

192.8
(93.6)

99.2

363.0

—
—
24.0

24.0

—
15.7
0.3

16.0

8.0
23.6
(0.1)

31.5
(2.8)

28.7

0.1

—
494.3
1.1

495.4

—
234.7
87.0

321.7

173.7
73.8
(62.0)

185.5
(42.3)

143.2

976.6

1,411.5
130.5
242.1

1,784.1

860.4
363.9
215.0

1,439.3

344.8
25.4
(176.5)

193.7
(93.5)

100.2

400.6

—
—
16.0

16.0

—
17.7
0.2

17.9

(1.9)
26.3
—

24.4
(0.1)

24.3

0.4

—
—
54.8

54.8

—
56.7
5.1

61.8

(7.0)
30.6
(0.3)

23.3
7.9

31.2

7.2

643.7

545.8

5.7
—
137.7

143.4

5.6
111.1
21.7

138.4

5.0
—
(7.9)

(2.9)
0.4

(2.5)

35.2

908.1

—

—
—
—

—

—
12.5
3.1

15.6

(15.6)
44.8
(99.5)

(70.3)
48.2

(22.1)

1.3

1,374.2
820.3
493.2

2,687.7

903.1
821.6
383.8

2,108.5

579.2
188.7
(380.6)

387.3
(87.5)

299.8

783.7

139.4

9,208.2

11.9

710.0

—
—
24.8

24.8

—
28.9
2.6

31.5

(6.7)
7.4
0.6

1.3
5.0

6.3

1.1

278.9

181.6

4.6
—
16.8

21.4

4.6
24.3
1.5

30.4

(9.0)
—
(1.4)

(10.4)
4.2

(6.2)

6.1

85.5

—

—
—
—

—

—
5.5
2.7

8.2

(8.2)
23.5
(73.6)

(58.3)
31.4

(26.9)

1,416.1
624.8
300.8

2,341.7

865.0
675.0
309.0

1,849.0

492.7
156.4
(312.9)

336.2
(95.3)

240.9

3.6

1,388.4

146.8

8,347.2

11.3

335.3

Total Assets

3,172.3

4,133.2

211.5

Investments Accounted for by the Equity Method

125.5

26.8

—

Liquids
Pipelines

Gas
Distribution

International

Gas
Pipelines

Energy
Services

Corporate2 Consolidated

Total Assets

2,908.0

4,736.0

192.0

Investments Accounted for by the Equity Method

115.4

27.0

—

Operating Segments (continued)

Year ended December 31, 1997

Operating Revenue
Gas sales
Transportation
Energy services and other

Expenses

Gas costs
Operating and administrative
Depreciation

Operating Income (Loss)
Investment and Other Income
Interest Expense

Earnings (Loss) Before Income Taxes
Income Taxes

Earnings (Loss)

Additions to Property, Plant and Equipment

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Liquids
Pipelines

Gas
Distribution

International

Gas
Pipelines

Energy
Services

Corporate 2 Consolidated

—
511.4
—

511.4

—
230.4
85.8

316.2

195.2
37.8
(66.6)

166.4
(58.0)

108.4

214.3

1,763.4
25.9
210.9

2,000.2

1,035.9
370.7
185.8

1,592.4

407.8
11.5
(164.1)

255.2
(123.1)

132.1

416.4

—
—
6.6

6.6

—
10.7
0.1

10.8

(4.2)
19.4
—

15.2
0.9

16.1

—

—
—
1.2

1.2

—
7.7
—

7.7

(6.5)
1.0
—

(5.5)
3.1

(2.4)

0.5

53.1

34.0

0.5
—
0.1

0.6

0.5
13.6
0.1

14.2

(13.6)
—
—

(13.6)
6.1

(7.5)

—

8.3

—

—
—
—

—

—
5.3
2.2

7.5

(7.5)
6.8
(45.4)

(46.1)
16.7

(29.4)

20.2

1,763.9
537.3
218.8

2,520.0

1,036.4
638.4
274.0

1,948.8

571.2
76.5
(276.1)

371.6
(154.3)

217.3

651.4

138.3

6,672.2

12.2

174.2

Total Assets

1,887.4

4,414.7

170.4

Investments Accounted for by the Equity Method

69.2

58.8

—

On October 1, 1999, the Corporation separated and removed (“unbundled”) the ancillary business activities from the regulated operations of Enbridge Consumers Gas to the
unregulated Energy Services segment. This intersegment transaction comprised the transfer of the water heater and furnace rental program, merchandise retailing and financing
operations and other related services including the transfer of associated assets for $737 million. The segmentation for 1999 reflects the results of operations of the unbundled
activities for the period October 1, 1999 to December 31, 1999 and the associated assets in the Energy Services segment. With the exception of a reduction in the total assets of
the Gas Distribution segment to account for the intersegment transfer of assets, the results of operations of the Gas Distribution segment reflects a full year contribution from the
ancillary business activities for the year ended September 30, 1999 under the quarter lag basis of consolidation.
Corporate reflects non operating investing and financing activities including general corporate investments and costs associated with financing non regulated activities.

Geographic Segments
There are no material operating revenues earned or capital assets owned outside of Canada which are consolidated
with the results of the Corporation. Foreign earnings are primarily derived from investments accounted for using the equity
or cost methods.

3. INVESTMENT AND OTHER INCOME

Year ended December 31,

Long term investments (Note 7)
Short term investments
Allowance for equity funds used during construction
Gain on sale of non strategic real estate
Gain on settlement of defeased debt (Note 7)
Settlement of outstanding insurance claim
Other

1999

139.6
11.9
9.9
—
—
—
27.3

188.7

1998

92.5
4.2
18.1
7.4
6.1
16.0
12.1

156.4

1997

74.5
—
3.2
—
—
—
(1.2)

76.5

T H E E N E R G Y B R I D G E

4. INTEREST EXPENSE

Year ended December 31,

Long term debt
Short term borrowings
Capitalized

1999

382.8
14.9
(17.1)

380.6

1998

322.2
14.5
(23.8)

312.9

1997

275.3
9.8
(9.0)

276.1

Short term borrowings, which primarily finance gas in storage and other working capital items, are comprised of commercial
paper with maturities of less than one year with a weighted average interest rate (including the effect of hedging
instruments) of 4.9% at December 31, 1999 (1998 – 5.4%; 1997 – 4.2%).

In 1999, total interest paid was $399.5 million (1998 – $319.7 million; 1997 – $267.7 million).

INCOME TAXES

The geographic components of pretax earnings and income taxes were as follows:

Year ended December 31,

Earnings before income taxes

Canada
United States
Other

Current income taxes

Canada
United States
Other

Deferred income taxes

Canada
United States

Income taxes

Deferred income taxes have arisen as a result of the following items:

Year ended December 31,

Recognition of tax losses available for carryforward
Timing of recognition of regulatory deferral accounts
Transfer of U.S. pipeline business to Master Limited Partnership
Other

1999

1998

1997

236.5
102.7
48.1

387.3

62.3
13.5
6.2

82.0

(3.4)
8.9

5.5

87.5

1999

(39.8)
44.7
6.0
(5.4)

5.5

212.6
88.2
35.4

336.2

89.4
29.8
2.2

121.4

(24.4)
(1.7)

(26.1)

95.3

1998

(14.5)
(14.2)
(2.7)
5.3

(26.1)

279.2
69.9
22.5

371.6

134.9
18.1
1.4

154.4

(5.0)
4.9

(0.1)

154.3

1997

—
—
2.3
(2.4)

(0.1)

Accumulated deferred income taxes which have not been recorded in the accounts amounted to $743.3 million at
December 31, 1999 (1998 – $679.9 million). Had the deferred method of tax allocation been prescribed by the regulatory
authorities for ratemaking purposes, such amounts would have been recorded and recovered in rates to date.

In October 1998, Revenue Canada changed its assessing practice relating to natural gas utilities with respect to the
treatment for tax purposes of certain capitalized expenditures. Effective for 1997 and subsequent taxation years, these
expenditures can now be expensed for tax purposes. Contingent upon OEB approval, the Corporation will refund the higher

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

taxes included in rate and revenue structures in 1999, 1998 and 1997 for non rental related operations of $14.1
million (1998 – $10.1 million). Lower taxes payable relating to rental operations for 1999, 1998 and 1997 of $42.3 million
(1998 – $32.0 million) were determined by the OEB in 1999 to be available to offset the Corporation’s liabilities on the
currently unrecorded deferred income taxes associated with the rental program. As at December 31, 1999, these amounts
are included in deferred credits.

Prior to 1992, the Corporation’s main Canadian crude oil pipeline system had collected through tolls $114.1 million which
had been recorded as deferred income taxes. Consistent with a mandate from its regulator and an agreement with the
Canadian Association of Petroleum Producers to repay these funds to its customers, the Corporation has reclassified
these deferred income taxes to deferred credits as a liability to shippers on its statement of financial position, to reflect
the planned repayment. A corresponding increase has been reflected in the amount of unrecorded deferred income taxes.
Prior years’ comparative amounts have been restated to conform with the current year’s financial statement presentation.
During 1999, $17.3 million of such funds were repaid to the shippers through lower tolls and $54.1 million has been
included in the current portion of long term liabilities.

The income tax provision differs from the amount that would have been expected using the combined Canadian federal
and provincial statutory income tax rate. The difference results from the items shown in the following table:

Year ended December 31,

Earnings before income taxes

Statutory income tax rate

Income taxes at statutory rate
Increase (decrease) resulting from:

Non provision of deferred income taxes on regulated operations
Non taxable items, net
Lower effective foreign tax rates
Income taxes recoverable relating to prior years
Large Corporations Tax in excess of surtax
Other

Income taxes

Effective income tax rate

1999

387.3

44.6%

172.7

(37.1)
(48.7)
(16.0)
1.6
14.4
0.6

87.5

1998

336.2

44.6%

150.0

(18.6)
(2.9)
(27.1)
(17.3)
10.1
1.1

95.3

22.6%

28.4%

In 1999, income taxes paid amounted to $79.6 million (1998 – $163.5 million; 1997 – $172.1 million).

6. CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,

Accounts receivable and other
Gas in storage
Deferred charges and other
Accounts payable and other
Interest payable
Current portion of long term liabilities
Deferred credits

1999

(67.2)
(17.3)
(38.6)
9.7
(1.8)
54.1
(70.7)

(131.8)

1998

(174.7)
(47.9)
(9.4)
(14.3)
17.0
—
51.3

(178.0)

1997

371.6

44.6%

165.7

(20.2)
15.0
(17.5)
—
7.5
3.8

154.3

41.5%

1997

(75.5)
(30.8)
(5.0)
56.7
(8.2)
—
13.7

(49.1)

Changes in accounts payable shown above exclude changes in construction payable which relate to investing activities.

T H E E N E R G Y B R I D G E

7. LONG TERM INVESTMENTS

December 31,

Noverco Inc.

Preference shares
Common shares
Reciprocal shareholding

Alliance Pipeline Project
AltaGas Services Inc.
Colombia Pipeline
U.S. Master Limited Partnership
Vector Pipeline Project
Other

1999

1998

181.4
148.7
(121.9)

208.2
306.5
165.6
160.2
82.9
59.4
68.8

1,051.6

181.4
148.9
(121.9)

208.4
146.2
—
160.2
68.3
29.3
64.5

676.9

Noverco Inc.
On August 27, 1997, the Corporation purchased Noverco preference shares for $181.4 million and 32% of Noverco’s
common shares for $151.0 million. Noverco is a holding company which has, as its principal asset, a 77% interest
(1998 – 80%) in Gaz Métropolitain and Company, Limited Partnership, which is engaged in natural gas distribution in
Quebec and Vermont, and which also holds a 50% interest in TQM Pipeline and Company, Limited Partnership, which owns
and operates a pipeline transporting natural gas in Quebec. This acquisition was financed by a combination of debt ($45.3
million) and 12.0 million common shares of Enbridge issued to Noverco in a separate transaction ($287.1 million). Noverco
also acquired a warrant to purchase from the Corporation 3.0 million additional common shares on June 30, 1998 at a
price of $25.50 per share.

On June 30, 1998, the warrant was exercised and on November 13, 1998, was settled for proceeds of $76.5 million.
Consequently, Noverco’s common share interest in the Corporation increased to approximately 10% from 8%. Additionally,
on November 13, 1998, in conjunction with a separate public offering, 500,000 common shares were issued to
Noverco at a price of $33.525 per share, maintaining Noverco’s reciprocal shareholding interest in Enbridge at 10%. As
a result of the reciprocal shareholdings, the Corporation has a pro rata interest of 3.2% in its own shares (1998 –
3.2%). Accordingly, both the investment in Noverco and shareholders’ equity have been reduced by the reciprocal
shareholding of $121.9 million (1998 – $121.9 million).

The investment in common shares of Noverco is accounted for on the equity basis while the investment in preference
shares is accounted for at cost. The investment in the common shares of Noverco includes $122.6 million (1998 – $129.3
million) representing the unamortized excess of the purchase price over the net book value of those shares at the date
of acquisition. For equity accounting purposes, the excess was allocated to property, plant and equipment, on the basis
of estimated fair values, and is being amortized over the economic life of such assets. The preference shares, which are
non voting and redeemable on July 2, 2031, entitle the Corporation to a cumulative dividend based on the yield of 10
year Government of Canada bonds plus 4.45%. In 1999, earnings from Noverco amounted to $17.6 million (1998 – $17.7
million; 1997 – $6.9 million). At December 31, 1999, the carrying value of the investment in Noverco common shares
included unremitted equity earnings of $7.1 million (1998 – $0.5 million).

Alliance Pipeline Project
The Corporation holds a 21.4% equity interest in the Alliance Pipeline Partnership. The Partnership is presently constructing
a natural gas pipeline from Fort St. John, British Columbia, to Chicago, Illinois, which is anticipated to be in service late
in 2000. The Alliance Pipeline has a planned delivery capacity of 1.3 billion cubic feet per day of which 105 million cubic
feet has been committed by the Corporation. From time to time, the Corporation is required to provide further funds
upon call of the Partnership. During 1999, the Corporation invested $138.0 million in the project (1998 – $105.4
million; 1997 – $30.5 million) and recorded $22.3 million (1998 – $6.5 million; 1997 – $1.0 million) of equity earnings.
At December 31, 1999, the carrying value of the investment in the Partnership included unremitted equity earnings of
$29.8 million (1998 – $7.5 million).

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

AltaGas Services Inc.
On September 30, 1999, the Corporation purchased non voting participating preference shares of AltaGas Services Inc.
for $90.0 million and 7.3 million of AltaGas’ common shares for $73.8 million. On an aggregate basis the participating
and common shares represent an approximate 40% interest in AltaGas. AltaGas is a holding company which, through its
wholly owned subsidiaries, provides natural gas gathering, processing, and related services as well as natural gas
transmission and distribution to end users in Alberta and Saskatchewan. This acquisition was financed by a combination
of cash ($156.7 million) and 217,330 common shares of Enbridge ($7.1 million).

The investment in participating and common shares of AltaGas is accounted for on the equity basis. The participating
shares fully participate in the earnings of AltaGas and are convertible into common shares on a one to one basis at the
option of Enbridge. Should Enbridge not convert these shares into common shares by September 30, 2004, then
AltaGas will be required to convert all participating shares prior to September 30, 2009, based on a ratio of $10 divided
by the current market value of an AltaGas common share. The investment in the common shares of AltaGas includes
$39.2 million representing the unamortized excess of the purchase price over the net book value of those shares at the
date of acquisition. For equity accounting purposes, the excess was allocated to property, plant and equipment, on the
basis of estimated fair values, and is being amortized over the economic life of such assets. In 1999, earnings from
AltaGas amounted to $2.0 million. At December 31, 1999, the carrying value of the investment in AltaGas participating
and common shares included unremitted equity earnings of $2.0 million.

Colombia Pipeline
Pursuant to an agreement with a consortium of crude oil producers/shippers, the Corporation has made a long term
investment in a pipeline in Colombia. From time to time, the Corporation was required to provide funds upon the call of
the parties to the agreement. During 1999, the Corporation did not make additional investments in the pipeline as the
Corporation had no remaining commitment to provide further funds. During 1998, the Corporation contributed U.S. $2.5
million (1997 – U.S. $38.7 million). Under a separate agreement, the Corporation acts as one of the operators of the
pipeline and earns operating fees.

The Corporation earns a fixed rate of return on its investment and has no residual interest in the assets of the pipeline.
Accordingly, the investment is accounted for on the cost basis. The investment is to be redeemed in equal payments
over a ten year period. Subject to certain conditions, redemption may commence in 2003 but, in any event, no later than
2012. Earnings amounted to $24.0 million in 1999 reflecting the fixed rate of return on the investment as well as the
operating and incentive fees (1998 – $24.8 million; 1997 – $18.5 million).

U.S. Master Limited Partnership
The portion of the main liquids pipeline system located in the United States is owned by Lakehead Pipe Line Partners,
L.P., a U.S. Master Limited Partnership. The Corporation’s wholly owned U.S. subsidiary, Lakehead Pipe Line Company,
Inc. (Lakehead), holds an equity interest of approximately 15.3% in the Partnership, and manages and operates the U.S.
pipeline business as the General Partner.

The Corporation’s interest in the net income of the Partnership, adjusted for the allocation of depreciation on an
historical cost basis for assets contributed on formation of the Partnership, and including incentive distributions amounted
to $31.6 million (1998 – $33.7 million; 1997 – $26.4 million). In 1999, the Corporation received cash distributions of
$35.0 million from the Partnership (1998 – $31.8 million; 1997 – $21.8 million). The carrying value of the Corporation’s
investment in the Partnership includes unremitted equity earnings of $12.0 million (1998 – $15.4 million).

In 1999 and 1997, the Partnership completed public issues of additional Partnership Units. As the Corporation elected
not to participate in these offerings its effective equity interest in the Partnership was reduced to 15.3% from 16.6% in
1999 and to 16.6% from 18.0% in 1997. The proceeds received by the Partnership were allocated among the capital
accounts of the unitholders based upon the increase in Partnership net assets attributable to each interest as a result
of the issue. The Corporation’s pro rata share of Partnership net assets increased by $18.2 million and $16.3 million,
which were recognized in earnings in 1999 and 1997, respectively.

Financing of the Partnership was previously facilitated through Lakehead Services, Limited Partnership. The Corporation
owns a 99% limited partner interest in the Services Partnership and the Partnership holds a 1% general partner
interest. At December 31, 1997, the Services Partnership had borrowings of U.S. $52 million under a Revolving Credit

T H E E N E R G Y B R I D G E

Facility Agreement. In conjunction with its borrowings under this facility, the Services Partnership irrevocably placed U.S.
government securities in a trust to be used solely for satisfying scheduled payments of both interest and principal on
these borrowings. This transaction was recognized as an in substance defeasance and the debt was considered to be
extinguished. In 1998, as a result of the cessation of financing activities of the Services Partnership and the corresponding
release of trust assets in excess of defeased debt requirements, the Corporation recovered $6.1 million which were
recognized in earnings.

Vector Pipeline Project
The Corporation holds a 45% interest in the Vector Pipeline Partnership and is the operator of the project. The Partnership
is constructing a natural gas transmission line between Chicago, Illinois, and Dawn, Ontario, for a cost of approximately
U.S.$504 million. The Vector Pipeline has a planned delivery capacity of 1 billion cubic feet per day of which 260 million
cubic feet has been committed by the Corporation. From time to time during construction, the Corporation is required to
provide further funds upon call of the Partnership. During 1999, the Corporation invested $24.6 million in the project (1998
– $23.0 million) and recorded $5.5 million (1998 – $1.4 million) of equity earnings. At December 31, 1999, the carrying
value of the investment in the Partnership included unremitted equity earnings of $6.9 million (1998 – $1.4 million).

Other
Other investments include the Corporation’s 23% equity investment in the Chicap Pipe Line acquired in September
1998 for $33.3 million and a 44% equity investment in the Frontier Pipeline. The Chicap Pipe Line transports crude oil
between refining centres of Patoka and Chicago, Illinois. The Frontier Pipeline transports crude oil from Casper,
Wyoming, to Salt Lake City, Utah. During 1999, the Corporation recorded $11.2 million (1998 – $5.8 million; 1997 – $4.7
million) in equity earnings from these investments. At December 31, 1999, the carrying value of these investments included
unremitted equity earnings of $4.8 million (1998 – $3.5 million).

8. ACQUISITION OF SUBSIDIARIES

Cornwall Electric
On July 31, 1998, the Corporation acquired all of the outstanding shares of Cornwall Street Railway Light & Power Company
Limited for cash consideration of $68.0 million. Cornwall Electric provides electrical power to the residents of Cornwall,
Ontario, and surrounding areas. This investment, which was accounted for using the purchase method, exceeded the book
value of the assets by $27.0 million. This excess was allocated to property, plant and equipment, on the basis of estimated
fair values and is being amortized over the economic life of such assets.

9. PROPERTY, PLANT AND EQUIPMENT, NET

December 31, 1999

Liquids Pipelines
Gas Distribution
Gas Pipelines
Energy Services
Other

December 31, 1998

Liquids Pipelines
Gas Distribution
Gas Pipelines
Energy Services
Other

Weighted Average
Depreciation Rate

2.6%
2.7%
4.0%
4.5%
10.2%

Weighted Average
Depreciation Rate

2.9%
2.6%
4.0%
5.3%
10.3%

Cost

4,082.9
3,583.0
107.3
912.0
26.9

8,712.1

Cost

3,715.9
4,218.5
103.0
10.2
23.6

8,071.2

Accumulated
Depreciation

1,247.1
353.1
40.8
294.8
5.6

1,941.4

Accumulated
Depreciation

1,144.0
521.0
37.1
2.0
2.9

1,707.0

Net

2,835.8
3,229.9
66.5
617.2
21.3

6,770.7

Net

2,571.9
3,697.5
65.9
8.2
20.7

6,364.2

The average depreciation rate for the Gas Distribution segment, after inclusion of a provision for future removal and site
restoration costs, is 5.0% (1998 – 5.0%).

10. DEBT

Long Term Debt

December 31,

Regulated Operations
Liquids Pipelines
Debentures 1
Medium term notes
Variable rate

Gas Distribution
Debentures
Medium term notes
Other 2
Preference shares

Total regulated operations

Non Regulated Operations

Debentures 3
Medium term notes
Variable rate

Total non regulated operations

Total long term debt
Current portion of long term debt

Long term debt

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Weighted Average
Interest Rate

Maturity

1999

1998

9.1%
6.5%
5.1%

10.9%
6.5%
7.1%

2000–2024
2001–2029

2000–2024
2000–2028

9.4%
5.8%
5.4%

2000–2048
2002–2028

411.6
702.0
23.5

430.9
511.7
96.8

1,137.1

1,039.4

717.4
1,115.0
109.5
—

1,941.9

3,079.0

237.0
694.3
1,379.8

2,311.1

5,390.1
(105.3)

5,284.8

724.9
1,161.0
108.8
100.0

2,094.7

3,134.1

228.1
499.4
882.7

1,610.2

4,744.3
(242.0)

4,502.3

1
2
3

Includes $14.5 million of debentures (1998 – $54.1 million) secured by a first mortgage on specific pipeline properties and the assignment of the benefits of a shipping agreement.
Primarily comprised of commercial paper borrowings effectively converted into long term debt maturing in 2002 through the use of long term interest rate swaps.
Includes U.S. $130.0 million 9.4% debentures issued in 1995 which were effectively converted into Canadian $178.1 million at an effective interest rate of 8.8% reflecting the use
of a cross currency swap and the amortization of both debenture purchase warrant proceeds totaling $13.3 million and hedging costs over the life of the primary instrument.

The amounts of long term debt maturities and sinking fund requirements for the years ending December 31, 2000 through
2004, in millions, are $105.3, $430.2, $315.3, $140.3 and $164.6, respectively. Fixed rate long term debt retirements
in 1999 totalled $183.1 million (1998 – $360.8 million; 1997 – $94.2 million).

Preference Shares of Gas Distribution Segment
The Cumulative Redeemable Retractable Preference Shares of Enbridge Consumers Gas (Group 2 $1.6125 Series C –
2,000,000 shares, $50.0 million; Group 3 $1.43 Series C – 2,000,000 shares, $50.0 million) were redeemed in 1999,
both at $25 per share. Dividends on these shares for the year ended December 31, 1999, amounted to $2.5 million
and are included in interest expense (1998 – $6.1 million; 1997 – $6.1 million).

Credit Facilities
At December 31, 1999, the Corporation’s credit facilities in the amount of $2,707.6 million comprised the following:

Liquids Pipelines
Gas Distribution
Other

Committed

Uncommitted

Drawdowns

150.0
300.3
1,950.0

2,400.3

—
307.3
—

307.3

—
14.4
650.0

664.4

Committed facilities carry a weighted average standby fee of 0.087% per annum on the unutilized portion. The
committed facilities for the Liquids Pipelines and Gas Distribution segments expire in 2000 and are extendible annually
subject to the approval of the lenders. The committed facility for corporate purposes expires in 2004. Drawdowns under
these facilities bear interest at prevailing market rates.

T H E E N E R G Y B R I D G E

Non Controlling Interest Preference Shares
On July 5, 1999, Enbridge Consumers Gas issued 4,000,000 Cumulative Redeemable Convertible Preference Shares
for $100 million which bear dividends at 4.67% until July 1, 2002 after which the annual dividend will float in relation to
prime rate. At this date and every five years thereafter, the holder may convert these shares into a different preference
share bearing a fixed coupon rate based upon Canadian treasury bill yields. Also on and after July 1, 2002, Enbridge
Consumers Gas has the option to redeem the shares for $25.50 if the shares are publicly listed or $25 if they are not,
together with accrued and unpaid dividends in each case. As the holder of the share does not control cash redemption
rights and only participates in the earnings of Enbridge Consumers Gas these shares have been considered as a non
controlling interest.

11. SHARE CAPITAL

The authorized share capital of the Corporation consists of an unlimited number of common and preferred shares.

Common Shares

1999

1998

1997

(number of common shares in thousands)

Balance at beginning of year
Dividend Reinvestment and Share Purchase Plan
Investment by Noverco (Note 7)
Shares issued for investment in AltaGas (Note 7)
Public issue
Other

Balance at end of year

Number

155,710
200
—
217
—
181

156,308

Amount

1,659.8
6.6
—
7.1
—
3.7

1,677.2

Number

148,328
178
3,500
—
3,500
204

155,710

Amount

1,441.8
5.6
93.3
—
114.5
4.6

1,659.8

Number

134,980
1,222
12,000
—
—
126

148,328

Amount

1,126.2
26.2
287.1
—
—
2.3

1,441.8

Preferred Shares
On December 1, 1998, the Corporation completed a public offering of 5,000,000 5.5% Cumulative Redeemable Preferred
Shares, Series A, for cash proceeds of $125.0 million less related issue costs. The preferred shares are entitled to
fixed cumulative preferential dividends of $1.375 per share per year, payable quarterly. On or after December 31, 2003,
the Corporation may, at its option, redeem all or a portion of the outstanding preferred shares for $26.00 per share if
redeemed on or prior to December 1, 2004; $25.75 if redeemed on or prior to December 1, 2005; $25.50 if redeemed
on or prior to December 1, 2006; $25.25 if redeemed on or prior to December 1, 2007; and at $25.00 per share if
redeemed thereafter, in each case with all accrued and unpaid dividends to the redemption date. The after tax issue costs
of these shares totalling $1.7 million have been charged to retained earnings.

Preferred Securities
On July 8, and October 21, 1999, the Corporation completed public offerings of Preferred Securities which are unsecured
junior subordinated instruments that mature in 2048 and may be redeemed at the Corporation’s option in whole or in part
after the fifth anniversary of each issue. The Corporation has the right to defer, subject to certain conditions, payments of
distributions on the securities for a period of up to 20 consecutive quarterly periods. Such deferred distribution amounts
are payable in cash, or at the option of the Corporation, from the proceeds on the sale of equity securities delivered to the
trustee of the securities. Accordingly, the securities are classified into their debt and equity components as shown below:

Date of Issue

July 8, 1999
October 21, 1999

Number of
Securities

7 million
7 million

Redeemable
Face Value

175.0
175.0

Maturity Date

June 30, 2048
September 30, 2048

Debt

4.9
4.0

Equity

170.1
171.0

Distributions on these securities are payable at an annual rate of 7.6% for the July issue and 8.0% for the October
issue. These distributions are deductible for tax purposes by the Corporation and the after tax amount of the distributions
is charged to earnings applicable to common shareholders. The after tax issue costs of these securities totalling $6.0
million have been charged to retained earnings.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Earnings Per Common Share
Earnings per common share are computed on the weighted average number of common shares outstanding of
150,995,000, 145,448,000 and 137,808,000 in 1999, 1998 and 1997, respectively. The prior years have been restated
to reflect a two for one common share split on May 10, 1999. On a full year basis, there were no materially dilutive
instruments outstanding during each of the years in the three year period ended December 31, 1999. The weighted average
number of shares outstanding have been reduced by the Corporation’s pro rata interest in its own common shares resulting
from the investment in Noverco (Note 7). For the purposes of the calculation, earnings have been reduced by the preferred
security distributions and preferred share dividends.

Dividend Reinvestment and Share Purchase Plan
The Corporation has a Dividend Reinvestment and Share Purchase Plan. Under the Plan, registered shareholders may
reinvest dividends in common shares of the Corporation, or make optional cash payments to purchase additional common
shares, in either case free of brokerage or other charges.

Shareholder Rights Plan
The Corporation has a Shareholder Rights Plan designed to encourage the fair treatment of shareholders in connection
with any takeover offer for the Corporation. Rights issued under the Plan become exercisable when a person, and any
related parties, acquires or announces its intention to acquire 20% or more of the Corporation’s outstanding common
shares without complying with certain provisions set out in the Plan, or without approval of the Board of Directors of the
Corporation. Should such an acquisition or announcement occur, each rights holder, other than the acquiring person and
related parties, will have the right to purchase common shares of the Corporation at a 50% discount to the market price
at that time.

12. STOCK OPTION PLAN

The Corporation’s Incentive Stock Option Plan (1999) is comprised of fixed stock options and performance based stock
options. A maximum of 12 million common shares are reserved for issuance under the various alternatives covered by
the Plan. The details for the options outstanding have been restated to retroactively reflect the two for one common share
split on May 10, 1999.

Fixed Stock Options and Stock Appreciation Rights
Full time key employees are granted options to purchase unissued common shares, exercisable at the market price of
common shares at the date the options are granted. Generally, options vest in equal annual instalments over a four year
period and expire after ten years from the original issue date.

Stock Appreciation Rights (SARs) may be granted in connection with the grant of fixed stock options in an amount not
exceeding the number of shares to which the options relate. SARs are exercisable at such times and such amounts as
the underlying options, and entitle the holders to surrender the underlying and unexercised options in exchange for the
amount by which the market price of the common shares covered by the options exceeds the option exercise price. No
further SARs have been granted since November 3, 1994. The previous plans also allowed the Corporation to provide for
option holders Restricted Stock Units (RSUs) equivalent to the amount of dividends that would have been received on the
number of common shares subject to unexercised options. No further RSUs have been allowed since July 10, 1997. A
summary of the status of the Corporation’s fixed stock options is presented below:

(options in thousands; exercise prices in dollars)

Number of shares under option at beginning of year
Options granted
Options exercised
Options cancelled or expired

Number of shares under option at end of year 1

1999

Weighted Average
Exercise Price

Number

2,415
888
(115)
(72)

3,116

23.33
34.45
15.35
30.25

26.63

1998
Weighted Average
Exercise Price

18.45
33.11
15.02
22.22

23.33

Number

1,874
811
(128)
(142)

2,415

1997
Weighted Average
Exercise Price

15.15
24.38
12.84
16.92

18.45

Number

1,384
644
(128)
(26)

1,874

At December 31, 1999, there remained 376,000 and 656,000 unexercised stock options which had the SAR and RSU features, respectively.

T H E E N E R G Y B R I D G E

The options outstanding at the end of 1999 had the following characteristics:

(options in thousands; exercise prices in dollars)
Exercise Price Range

11.43 to 20.00
20.01 to 30.00
30.01 to 35.50

Number
Outstanding

Weighted Average
Exercise Price

Number Available
for Exercise

Weighted Average
Exercise Price

951
522
1,643

15.45
24.36
33.82

917
311
193

15.29
24.43
33.10

Outstanding stock options will expire over a period ending no later than August 17, 2009.

Performance Based Stock Options
The Plan provides for the granting of performance based options to executive management with vesting based upon the
performance of the Corporation’s common stock price. The options become exercisable, as to 50% of the grant, when
the market price of a common share exceeds $40.00 per share for 20 consecutive trading days during the period January
20, 1998 to December 31, 2002. If the share price exceeds $45.00 during the same period the grant is fully
exercisable. A summary of the status of the Corporation’s performance based options is presented below:

(options in thousands; exercise prices in dollars)

Number of shares under option at beginning of year
Options granted
Options cancelled

Number of shares under option at end of year

1999

Weighted Average
Exercise Price

31.40
33.88
31.35

31.60

Number

1,420
120
(60)

1,480

1998
Weighted Average
Exercise Price

31.39
31.35

31.40

Number

—
1,620
(200)

1,420

The performance based options expire on January 1, 2003 but will extend to January 20, 2006 if the options become
exercisable before December 31, 2002. None of the performance based options have met the vesting conditions at
December 31, 1999.

13. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments
The fair value of financial instruments represent an approximation of amounts that would have been received from or paid
to counterparties, calculated at the reporting date, to settle these instruments prior to maturity. At December 31, 1999,
the Corporation had no intention of settling any instruments prior to maturity. Carrying amounts of financial instruments
represent amounts recorded in the consolidated statement of financial position.

With the exception of the items listed below, the estimated fair values of all financial instruments approximate the
carrying amounts.

December 31,

Long term debt

Regulated operations
Non regulated operations

1999

1998

Carrying
Amount

3,079.0
2,311.1

Fair
Value

3,351.5
2,286.5

Carrying
Amount

3,134.1
1,610.2

Fair
Value

3,616.0
1,642.7

The following methods and assumptions were used to estimate the fair value of each class of financial instruments at
December 31, 1999 and 1998:

(cid:2)

The fair value of long term debt is based on quoted market prices at year end or based on the discounted future cash
flows of each debt issue at current interest rates for remaining average terms to maturity. Due to the regulatory
nature of business operations, the Corporation has the ability to recover related interest on debt at existing rates.

The carrying amount of the Corporation’s long term investment in the Colombia Pipeline Project approximates fair value
as the contractual rate of return represents current market rates for investments with similar terms and conditions.

The carrying amounts of all financial instruments classified as current approximate fair value because of the short
maturities of these instruments.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Risk Management
By virtue of its business operations, the Corporation is exposed to movements in the U.S./Canadian dollar exchange rate,
the price of natural gas and interest rates. In order to minimize these exposures for both its ratepayers and shareholders,
the Corporation utilizes a variety of hedging instruments to create an offsetting position to specific exposures. These
instruments are employed in connection with an underlying asset, liability or anticipated transaction, and are not used
for speculative purposes.

By entering into these hedging instruments, the Corporation agrees to exchange with counterparties the difference between
fixed and variable amounts, calculated by reference to specific foreign exchange rates, interest rates, or natural gas
price indices based on a notional principal amount or notional quantity of natural gas. The notional amounts are not
recorded in the financial statements as they do not represent amounts exchanged by the counterparties.

The Corporation enters into off balance sheet risk management transactions only with creditworthy institutions that possess
strong investment grade credit ratings or where such transactions are secured with approved forms of collateral. For
transactions with terms of greater than five years, the Corporation may also retain the right to require a counterparty
(who would otherwise meet the Corporation’s credit criteria) to provide collateral within a specified time frame. As at
December 31, 1999, no material credit exposure existed as the Corporation was not party to any off balance sheet
instruments in a significant receivable position.

Foreign Exchange
The Corporation has an exposure to the U.S./Canadian dollar exchange rate primarily through its investments in U.S.
dollar denominated operations. The Corporation has established a hedging program to eliminate a portion of that long
term exposure. At December 31, 1999, the Corporation had entered into par forward and cross currency swaps to hedge
U.S. dollar denominated cash flows of approximately U.S. $39 million per annum (1998 – U.S. $39 million; 1997 – U.S.
$30 million) as well as the redemption of the U.S. dollar denominated investment in the Colombia pipeline project of U.S.
$100 million (1998 – $100 million), thereby mitigating potential currency exposures on the anticipated cash flows from,
and redemption of, these U.S. dollar investments. In addition, forward foreign exchange contracts, including cross
currency swaps, have been entered into to hedge the Corporation’s exposure on its U.S. dollar denominated debt and to
match the effect of translating Canadian dollar denominated monetary financing held by an integrated U.S. subsidiary.

Natural Gas Prices
The Corporation also uses natural gas price swaps, options and collars to manage exposure to natural gas prices which,
under the majority of system supply gas contracts, are indexed to U.S. dollar denominated natural gas futures contracts
plus a basis differential or to Alberta based gas price indices. As allowed under the regulatory framework governing the
Corporation’s Gas Distribution operations, the Corporation hedges the cost of a portion of future natural gas supply
requirements. Amounts paid or received under this risk mitigation strategy are recognized as part of the cost of the
underlying natural gas purchases which is recovered through the rate making process. The OEB continues to monitor
the implementation and results of the Corporation’s natural gas hedging program. At December 31, 1999, the Corporation
had entered into natural gas price swaps and options to effectively manage the price for approximately 10.3%, or 18.2
billion cubic feet, of its forecast fiscal 2000 system gas supply. During the year ended December 31, 1999, the Corporation
hedged 37.7%, or 62.0 billion cubic feet, of its system gas supply (1998 – 34%, or 53.4 billion cubic feet; 1997 – 36%,
or 65.7 billion cubic feet).

Interest Costs
To hedge against the effect of future interest rate movements on its short to long term borrowing requirements, the
Corporation enters into forward interest rate agreements, swaps and collars. In anticipation of future debt issuances
related to specific committed capital projects, the Corporation enters into financial contracts to hedge a portion of the
interest cost associated with the anticipated issues.

Fair Value of Off Balance Sheet Financial Instruments
The fair value of off balance sheet financial instruments reflects the estimated amounts that the Corporation would receive
or pay to terminate the contracts at the year end date. This fair value represents the difference between the present
value of estimated future receipts and future payments under the terms of each instrument which is estimated by obtaining
quoted market prices or by using pricing models widely used in financial markets. These fair value amounts should not
be viewed in isolation, but rather in relation to the fair values of the underlying hedged transactions and the overall reduction
in the Corporation’s exposure to adverse fluctuations in foreign exchange rates, natural gas prices and interest rates. At
December 31, 1999, the Corporation had no intention of settling any instruments prior to maturity.

T H E E N E R G Y B R I D G E

At year end, the Corporation was party to the following off balance sheet financial instruments:

December 31,

Foreign exchange

Cross currency swaps
Forwards (cumulative exchange amounts)

Natural gas prices (billion cubic feet)
Interest rates

Interest rate swaps
Bond forwards

Notional
Principal
or Quantity

316.2
1,832.3
18.2

696.3
—

1999
Fair Value
Payable/
(Receivable)

(3.4)
14.4
(0.3)

(1.3)
—

Maturity

2001–2022
2000–2022
2000

2000–2029

Notional
Principal
or Quantity

316.2
1,891.2
31.1

271.0
153.0

1998
Fair Value
Payable/
(Receivable)

Maturity

2.6
89.2
(3.5)

2001–2022
1999–2022
1999

6.9
8.5

1999–2002
1999

As the Corporation did not settle hedging instruments in advance of the hedged transactions, there were no gains or losses
deferred in relation to any of the Corporation’s off balance sheet hedges of anticipated transactions at December 31,
1999 and 1998.

Trade Credit Risk
Trade receivables relating to Liquids Pipelines consist primarily of amounts due from companies operating in the oil and
gas industry and are collateralized by the crude oil and other products contained in the Corporation’s pipeline and storage
facilities. The Corporation holds adequate insurance on this crude oil and other products. Credit risk with respect to trade
receivables of the remaining operating segments is reduced by the large and diversified customer base, and, for rate
regulated operations, the ability to recover an estimate for doubtful accounts through the ratemaking process. The allowance
for doubtful accounts amounted to $16.4 million at December 31, 1999 (1998 – $16.3 million).

14. POSTRETIREMENT BENEFITS

Pension Plans
The Corporation has three pension plans which provide either defined benefit or defined contribution pension benefits or
both for the employees of the Corporation. The Liquids Pipelines pension plan in Canada provides non contributory defined
benefit pension and/or defined contribution benefits to Canadian employees. The Liquids Pipelines pension plan in the
United States provides non contributory defined benefit pension benefits to U.S. employees. The Enbridge Consumers
Gas pension plan provides contributory defined benefit pension benefits to employees of the Gas Distribution and
Energy Services segments.

Defined Benefit
Retirement benefits under defined benefit plans are based on the employees’ years of service and remuneration. Contributions
made by the Corporation are in accordance with independent actuarial valuations and are invested primarily in publicly
traded equity and fixed income securities. The most recent actuarial valuation was performed as of January 1, 1999.

Pension costs under the defined benefit pension plan reflect management’s best estimates of the rate of return on pension
plan assets, rate of salary increases and various other factors including mortality rates, terminations and retirement ages.
Adjustments arising from plan amendments, experience gains and losses, and changes to assumptions are amortized
over the expected average remaining service lives of the employees.

Consistent with its ratemaking process, Enbridge Consumers Gas records as pension expense the contributions
deemed sufficient by actuaries to fully fund the plans over an acceptable time frame.

Defined Contribution
Defined contribution pension benefits cover all employees hired by the Liquids Pipelines segment in Canada after
January 1, 1997 as well as its existing employees who elected to leave the defined benefit plan on a prospective
basis. Contributions are based on each employee’s age and years of service. For defined contribution pension
benefits, pension expense equals amounts contributed by the Corporation.

The status of the Corporation’s pension plans was as follows:

December 31,

Pension plan assets at market values:

Liquids Pipelines
Canada
United States

Enbridge Consumers Gas

Projected benefit obligations:

Liquids Pipelines
Canada
United States

Enbridge Consumers Gas

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

1999

1998

191.3
174.0
668.7

1,034.0

155.4
74.4
404.2

634.0

169.8
161.9
564.6

896.3

124.9
98.3
411.5

634.7

The Corporation’s pension expense totaled $9.4 million (1998 – $5.0 million; 1997 – $9.2 million) and the deferred
pension asset was $21.3 million (1998 – $16.7 million).

Postretirement Benefits Other than Pensions
Postretirement benefits other than pensions include supplemental health, dental and life insurance coverage for
qualifying retired employees. The cost of providing these benefits amounted to $2.0 million (1998 – $2.6 million; 1997
– $1.7 million).

15. RELATED PARTY TRANSACTIONS

The U.S. Master Limited Partnership, which does not have any employees, uses the services of the Corporation for
managing and operating the U.S. pipeline business. These services, which are charged at cost in accordance with service
agreements, amounted to $50.9 million (1998 – $51.7 million; 1997 – $46.0 million). Accounts receivable include
$2.5 million due from the Partnership (1998 – $3.8 million).

The Partnership had entered into an easement agreement with Enbridge Holdings (Mustang) Inc. (“Enbridge Mustang”),
a wholly owned subsidiary of the Corporation. Enbridge Mustang acquired certain real property for the purposes of granting
pipeline easements to the Partnership for construction of a new pipeline, completed during 1998, by the Partnership from
Superior, Wisconsin, to Chicago, Illinois. In order to provide for these real property acquisitions by Enbridge Mustang, the
Partnership had made non interest bearing cash advances to Enbridge Mustang. As Enbridge Mustang disposes of the
real property, the advances are repaid. Under the terms of the agreement, the Partnership reimburses Enbridge
Mustang for the net cost of acquiring, holding and disposing of the real property. The advances amounted to $11.0 million
at December 31, 1999 (1998 – $49.4 million).

Lakehead is authorized by its Board of Directors to provide loans to the Partnership, on an uncommitted basis, in an
amount not to exceed U.S. $200 million. In late March 1999, the Partnership borrowed U.S. $25.0 million from Lakehead
at an interest rate of 7.75%. This loan was repaid in early April 1999. In late September 1998, the Partnership borrowed
U.S. $37.0 million from Lakehead at an interest rate of 8.75%. This loan was repaid in early October 1998.

16. COMMITMENTS AND CONTINGENCIES

Jose Crude Oil Storage and Ship Loading Terminal
In 1999, the Corporation entered into an agreement to acquire, through a Venezuelan general partnership, a 45% interest
in the U.S.$385 million Jose Crude Oil Storage and Ship Loading Terminal in Venezuela from PDVSA Petroleos y Gas, S.A.,
a subsidiary of Petroleos de Venezuela, S.A. The project entails the acquisition and operation of existing onshore and offshore
terminaling facilities within the Jose Industrial Complex (“Terminal”), a large petroleum and petrochemical complex. The
Terminal handles crude oil from eastern Venezuelan fields for loading onto tankers for export, with throughput capacity of
approximately 800,000 barrels per day. The Venezuelan Partnership has not received the final assent from the Venezuelan
Government to complete the acquisition. During the intervening period, PDVSA has engaged the Partnership to operate the
Terminal on its behalf. During 1999, the Corporation earned $6.3 million in fees for operating the Terminal.

T H E E N E R G Y B R I D G E

Enbridge Consumers Gas
Enbridge Consumers Gas is aware that the remediation of discontinued manufactured gas plant sites may become an
issue in the future. The probable overall cost of remediation measures cannot be determined at this time due to uncertainty
about the existence or extent of environmental risks, the complexity of laws and regulations particularly with respect to
sites decommissioned years ago and no longer owned by Enbridge Consumers Gas, and the selection of alternative
remediation approaches. Although there are no known regulatory precedents in Canada, there are precedents in the United
States for recovery of costs of a similar nature in rates. Enbridge Consumers Gas expects that, if it is found that it must
contribute to any remediation costs, it would be generally allowed to recover in rates those costs not recovered through
insurance or by other means and believes that the ultimate outcome of these matters would not have a significant
impact on its financial position.

In April 1994, an action was commenced against Enbridge Consumers Gas by a customer alleging that the OEB
approved late payment penalties charged to customers were contrary to Canadian federal law and seeking certification
of the action as a class action. The claim sought $112 million in restitutionary payments and other relief not calculated
or quantified in the claim on behalf of all people who were customers of Enbridge Consumers Gas who had paid or been
charged such penalties since April 1981. The class action was not certified by the Court although the Class Proceedings
Committee, established under the Ontario Class Proceedings Act, 1992 (the “92 Act”) decided that it would fund the
action. In February 1995, Mr. Justice Winkler, of the Ontario Court of Justice, General Division, issued a judgement in
favour of Enbridge Consumers Gas dismissing the class action lawsuit. He concluded that the late payment charge is
not interest payable on a credit transaction, but was an incentive to customers to pay their bills by a certain date. He
held that Section 347 of the Criminal Code (Canada), which deals with interest on credit transactions, did not apply. In
March 1995, the plaintiff’s solicitors filed notice of an appeal of the decision of the trial judge. In September 1996, the
Court of Appeal heard and dismissed the appeal. The plaintiff was granted leave to appeal to the Supreme Court of Canada
from the decision of the Court of Appeal and the appeal was heard in March 1998. On October 30, 1998, the Supreme
Court allowed the appeal and set aside the trial court’s summary judgement dismissing the action. The Supreme Court
rejected the argument of Enbridge Consumers Gas with respect to Section 347 and remitted the matter back to the trial
court for determination of all other issues including the other defenses raised in pleadings but not yet heard in court
and for proceedings in accordance with the 1992 Act. Enbridge Consumers Gas intends to defend the action before the
Ontario Court. Further motions for summary judgement and related matters have been brought by both the plaintiff and
Enbridge Consumers Gas to be heard by the Ontario Court commencing March 20, 2000.

U.S. Master Limited Partnership
Lakehead has agreed to indemnify the Partnership from and against substantially all liabilities, including liabilities relating
to environmental matters, arising from operations prior to the transfer of its pipeline operations to the Partnership in 1991.
This indemnification does not apply to amounts that the Partnership would be able to recover in its tariff rates (if not
recovered through insurance), or to any liabilities relating to a change in laws after December 27, 1991. In addition, in
the event of default, Lakehead, as the General Partner, is subject to recourse with respect to a portion of the Partnership’s
long term debt which amounted to U.S. $585 million at December 31, 1999.

Corporate
Provisions have been made for potential liabilities, if any, resulting from claims against the Corporation arising in the normal
course of business. Furthermore, in the case of income tax reassessments, where deemed appropriate, advance tax
payments are made to forestall non deductible interest potentially resulting from the outcome of contested reassessments.
Such payments are reflected in receivables in the statement of financial position. The ultimate outcome of these claims
cannot be determined at this time. However, in the opinion of management, liabilities in excess of the provisions made,
if any, would not be material.

Year 2000
The Year 2000 Issue arises because many computerized systems use two digits rather than four to identify a year. Date
sensitive systems may recognize the year 2000 as 1900 or some other date, resulting in errors when information using
year 2000 dates is processed. To the reporting date, the Year 2000 Issue has not had a negative impact on the
Corporation’s ability to conduct normal business operations, nor to the knowledge of the Corporation has had a significant
effect on the operations of its customers, suppliers or other third parties providing critical services.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

17. SUBSEQUENT EVENT

There are currently unrecorded deferred income taxes, related to the rental assets, in the amount of approximately $168
million. Enbridge Consumers Gas applied to the OEB for full recovery of these taxes in future gas distribution rates, as
ratepayers had benefited from the tax deductions in prior years by means of lower gas distribution rates. In March 1999,
the OEB released its decision and determined that $50 million of the projected amount may be recovered in future utility
rates, and a further $42 million in refunds from Revenue Canada relating to a change in its assessing practice can be
used to offset this deferred tax liability, leaving $76 million in future income tax liabilities to be borne by the shareholder.

In October 1999, Enbridge Consumers Gas filed an Application for Judicial Review asking the Divisional Court, Superior Court
of Justice to set aside the OEB’s order, and that the matter of the deferred taxes be referred back to the OEB for a rehearing.
The Application also seeks a declaration that Enbridge as the common shareholder of Enbridge Consumers Gas is not responsible
for deferred taxes and that Enbridge Consumers Gas be provided a full and fair opportunity to be heard with respect to any
considerations which may have led, or may lead, to the conclusion that deferred taxes are the responsibility of the shareholder.
The decision of the Divisional Court, Superior Court of Justice on whether to hear the appeal will be issued in due course.

On October 1, 1999, immediately prior to the transfer of the rental assets to the Energy Services segment, Enbridge
Consumers Gas adopted the new CICA Handbook recommendations with respect to income taxes which are effective
January 1, 2000. Under the quarter lag basis of consolidation, the timing of this adoption coincides with the required
adoption by the Corporation. As a result of adopting this new accounting standard and recording the $168 million of
deferred income taxes associated with the rental assets, the Corporation will record a charge to retained earnings in the
amount of $76 million, as well as a regulatory asset of $50 million, reflecting the future recovery from ratepayers, and
will recharacterize $42 million in deferred credits as future income taxes payable.

18. UNITED STATES ACCOUNTING PRINCIPLES

As a registrant with the United States Securities and Exchange Commission, the Corporation is required to reconcile its
financial results for significant differences between generally accepted accounting principles in Canada (Canadian
GAAP) and those accepted in the United States (U.S. GAAP). Although the accounting bodies of the two countries are
moving towards harmonization of accounting principles, current differences with U.S. GAAP result in variations in
reported earnings as well as differences in presentation and disclosure.

The following information describes the effect of differences between Canadian and U.S. GAAP on the Corporation’s
consolidated financial statements:

Earnings and Comprehensive Income
Year ended December 31,

Earnings under Canadian GAAP
Deferred income taxes
Preferred securities distributions

Earnings under U.S. GAAP
Foreign currency translation adjustment

Comprehensive income

Financial Position

December 31,

Accounts receivable and other
Long term investments
Deferred charges and other
Property, plant and equipment, net
Accounts payable and other
Long term debt
Deferred credits
Deferred income taxes
Preferred securities
Retained earnings
Foreign currency translation adjustment (debit)

1999

299.8
—
(5.0)

294.8
(14.8)

280.0

1998

240.9
—
—

240.9
(22.0)

218.9

1999

1998

Canada

678.5
1,051.6
278.7
6,770.7
494.6
5,284.8
157.8
254.5
341.1
503.1
(23.9)

U.S.

646.0
1,084.0
1,699.2
7,178.2
464.2
5,625.9
162.3
2,108.3
—
481.1
(1.9)

Canada

611.3
676.9
212.1
6,364.2
540.9
4,502.3
230.4
266.4
—
407.6
(9.1)

1997

217.3
(9.6)
—

207.7
9.6

217.3

U.S.

735.5
710.1
1,463.6
6,764.2
509.4
4,502.3
302.4
2,034.8
—
385.6
12.9

T H E E N E R G Y B R I D G E

Under U.S. GAAP, deferred income taxes of integrated foreign operations are considered monetary and translated at current exchange rates. Under Canadian GAAP, deferred
income tax liabilities of integrated foreign operations are considered non monetary and translated at historical exchange rates.

Under U.S. GAAP, the Corporation’s Preferred Securities and related distributions would be treated entirely as debt and interest expense, respectively. Under Canadian GAAP, where
repayment of the indebtedness is payable in whole or in part through equity instruments the instrument is apportioned into debt and equity components. The fair value of the equity
component, when classified as long term debt under U.S. GAAP, is $326.8 million at December 31, 1999.

Under U.S. GAAP, deferred income tax liabilities are recorded for regulated operations which follow the taxes payable method. As these deferred income taxes are recoverable
through future revenues, a corresponding deferred asset is also recorded. These assets and liabilities reflect changes in enacted income tax rates.

U.S. GAAP requires that the cost of postretirement benefits be determined using the accrual method. The application of the accrual method of accounting for pension and other
postretirement benefits for regulated operations has no effect on earnings as any difference from the allowed method of recovery is recognized as a deferred asset or credit and
would be recovered or refunded, respectively, through the regulatory process. The cost of these benefits as they relate to non regulated operations would not have a material effect
on earnings.

For business acquisitions, the purchase price allocation reflects the recognition of additional deferred income tax liabilities on the excess of the purchase prices over the net book
value of assets acquired and liabilities assumed. A corresponding increase to property, plant and equipment acquired is also recognized. In addition, a portion of the purchase
price is allocated to the unrecognized excess of pension plan assets over the projected benefit obligations at the date of acquisition. However, an offsetting deferred liability,
reflecting the expected future refund of such excess through the regulatory process, is also recognized.

Under U.S. GAAP, the Corporation’s investments in joint ventures are accounted for using either the equity or the cost method instead of proportionate consolidation.

Basic and fully diluted earnings per share applicable to common shareholders under U.S. GAAP for the year ended
December 31, 1999 were $1.91 (1998 – $1.66; 1997 – $1.51).

At December 31, 1999, accumulated other comprehensive income consisted solely of an accumulated foreign currency
translation adjustment of $(1.9) million (1998 – $12.9 million).

In addition to the above, included in the 1998 current portion of long term liabilities in the Statement of Financial
Position under Canadian GAAP is $100 million of Cumulative Redeemable Retractable Preference Shares of Enbridge
Consumers Gas which were redeemed in fiscal 1999. Under U.S. GAAP, these shares would be accounted for as non
controlling (minority) interest.

The following additional disclosures are required under U.S. GAAP:

Deferred Income Taxes
Deferred income taxes have arisen as a result of the following items:
December 31,

Differences between capital cost allowance and depreciation:

Property, plant and equipment
Long term investment

Recognition of taxes on:

Acquisition purchase price excess
Incremental revenue required for recovery of unrecorded taxes

Transfer of U.S. pipeline business to Master Limited Partnership
Other

Deferred income taxes

Pension Plans
Disclosures required under U.S. GAAP for pension plans are as follows:
Change in Pension Benefit Obligations
December 31,

Pension benefit obligations at beginning of year
Service cost
Interest cost
Amendments
Pension plan participants’ contributions
Actuarial (gain) loss
Benefits paid
Effect of exchange rate changes

Pension benefit obligations at end of year

1999

1998

765.3
25.6

431.1
598.4
216.4
71.5

781.7
25.9

425.3
531.6
222.2
48.1

2,108.3

2,034.8

1999

634.7
19.5
41.8
—
5.6
(32.5)
(30.8)
(4.3)

634.0

1998

578.9
17.6
41.1
1.7
5.7
8.2
(25.2)
6.7

634.7

Change in Pension Plan Assets
December 31,

Fair value of pension plan assets at beginning of year
Actual return on plan assets
Employer’s contributions
Pension plan participants’ contributions
Benefits paid
Other
Effect of exchange rate changes

Fair value of pension plan assets at end of year

Net Pension Asset
December 31,

Pension plan assets in excess of projected benefit obligations
Unrecognized prior service cost
Unrecognized pension plan surplus
Unrecognized net gain

Net pension asset under U.S. GAAP

Pension Cost
Year ended December 31,

Benefits earned during the year
Interest cost on projected benefit obligations
Expected return on plan assets
Amortization and deferral of unrecognized amounts
Amount credited to the Partnership

Pension (credit) expense under U.S. GAAP

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

1999

896.3
146.9
7.5
5.6
(30.8)
17.5
(9.0)

1,034.0

1999

400.0
7.2
(2.2)
(231.3)

173.7

1998

17.6
41.1
(54.1)
(5.2)
3.3

2.7

1998

900.7
7.6
4.0
5.7
(25.2)
(7.4)
10.9

896.3

1998

261.6
8.9
(3.0)
(114.1)

153.4

1997

14.5
40.4
(54.7)
(4.2)
0.7

(3.3)

1999

21.0
41.8
(65.6)
(6.8)
6.1

(3.5)

Economic Assumptions
The most significant economic assumptions made in the measurement of the pension costs and the projected benefit
obligations of the pension plans were as follows:
Year ended December 31,

1999

1998

1997

Discount rate
Average rate of salary increases
Average rate of return on pension plan assets

6.3–7.5%
4.0–4.5%
7.5–8.0%

6.3–8.5%
4.5–5.5%
7.5–8.5%

6.5–8.5%
4.8–5.5%
8.0–8.5%

Postretirement Benefits Other Than Pensions
Postretirement benefits other than pensions include supplemental health, dental and life insurance coverage for retired
employees. U.S. GAAP requires the accrual, during the years the employees render service, of the expected cost of providing
these benefits to employees, their beneficiaries and qualified dependants.

Postretirement Benefit Obligations
Based on actuarial valuations dated January 1, 1999, the status of the Corporation’s postretirement benefit plans was as follows:
Change in Postretirement Benefit Obligations
December 31,

1999

1998

Postretirement obligations at beginning of year
Service cost
Interest cost
Benefit plan participants’ contributions
Actuarial loss
Benefits paid
Effect of exchange rate changes

Postretirement benefit obligations at end of year

112.0
3.9
7.7
0.3
0.2
(3.0)
(1.7)

119.4

85.7
3.2
7.1
0.2
17.0
(3.6)
2.4

112.0

T H E E N E R G Y B R I D G E

Change in Postretirement Benefit Plan Assets
December 31,

Fair value of postretirement benefit plan assets at beginning of year
Actual return on plan assets
Employer’s contributions
Benefit plan participants’ contributions
Benefits paid
Effect of exchange rate changes

Fair value of postretirement benefit plan assets at end of year

Net Postretirement Benefit Obligations
December 31,

Accumulated postretirement benefit obligations in excess of plan assets
Unrecognized prior service cost
Unrecognized net transition obligation
Unrecognized net loss

Net postretirement benefit obligations under U.S. GAAP

Postretirement Benefit Cost
Year ended December 31,

Service cost
Interest cost
Expected return on plan assets
Amortization and deferral of unrecognized amounts
Amount charged to the Partnership

Postretirement benefit cost under U.S. GAAP

1999

1998

18.4
0.3
5.0
0.3
(3.0)
(1.0)

20.0

1999

99.4
(7.8)
(41.7)
(10.4)

39.5

13.0
2.3
5.3
0.2
(3.6)
1.2

18.4

1998

93.6
(8.4)
(45.8)
(10.6)

28.8

1999

3.9
7.7
(0.8)
4.6
(3.1)

12.3

1998

1997

3.2
7.1
(0.8)
4.2
(3.1)

10.6

2.5
6.7
(0.5)
3.6
(2.7)

9.6

Economic Assumptions
The most significant economic assumptions made in the measurement of the postretirement benefit costs and the
projected benefit obligations were as follows:
Year ended December 31,

1998

1997

1999

Discount rate
Medical cost trend rate
Dental cost trend rate

6.5–7.5%
4.5–6.8%
4.5–6.0%

6.5–8.5%
4.5–7.0%
4.5–6.0%

6.5–7.3%
4.5–7.0%
6.0%

A 1% change in the assumed medical and dental care trend rate would result in a $17.1 million change in the accumulated
postretirement benefit obligations and a $2.7 million change in postretirement benefit costs.

Stock Option Plan
The Corporation provides stock based compensation in the form of stock options to full time key employees. At the time
of grant, the exercise price is equal to the market price and accordingly, no compensation expense is recognized under
the Corporation’s accounting policies. Under U.S. GAAP, a compensation cost is measured at the grant date in accordance
with a fair value based method utilizing an option pricing model. Companies electing not to recognize the compensation
cost determined under the fair value based method must make pro forma disclosure of net income and net income per
share as if that method of accounting had been applied. Had the Corporation applied the fair value based method, the
adjustment to earnings and earnings per share would not have been material.

Accounting for Derivative Instruments and Hedging Activities
On June 30, 1998, the Financial Accounting Standards Board (FASB) issued FAS 133 Accounting for Derivative Instruments
and Hedging Activities effective January 1, 2000. On June 23, 1999, the FASB issued FAS 137 which deferred the effective
date of FAS 133 by one year. The new standard has not been adopted by the Corporation as at December 31, 1999 and
the impact on the consolidated financial statements has not been determined.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Supplementary Information
(unaudited)

SELECTED QUARTERLY FINANCIAL DATA1
(Canadian dollars in millions, except per share amounts)

1999 Quarters

Operating revenue
Operating income
Earnings applicable to common shareholders
Earnings per common share
Dividends per common share

1998 Quarters

Operating revenue
Operating income
Earnings applicable to common shareholders
Earnings per common share
Dividends per common share

QUARTERLY SHARE TRADING INFORMATION 1

The Toronto and Montreal Stock Exchanges
1999 Quarters (Canadian dollars)

First

588.4
121.7
69.8
0.47
0.2875

First

628.1
139.5
62.2
0.43
0.2725

High
Low
Close
Volume (thousands)

1998 Quarters (Canadian dollars)

High
Low
Close
Volume (thousands)

The NASDAQ National Market
1999 Quarters (U.S. dollars)

High
Low
Close
Volume (thousands)

1998 Quarters (U.S. dollars)

High
Low
Close
Volume (thousands)

Second

1,049.9
283.6
178.4
1.18
0.3025

Second

894.4
256.6
147.6
1.02
0.2725

First

36.33
33.25
33.43
12,576

First

33.75
30.25
31.83
17,256

First

24.13
22.31
22.38
147

First

23.50
21.32
22.32
228

Third

552.2
105.1
36.5
0.24
0.3025

Third

466.0
90.8
38.8
0.27
0.2875

Second

35.00
31.50
33.75
14,106

Second

33.33
30.00
33.13
18,648

Second

24.88
21.38
23.00
181

Second

22.63
20.82
22.63
158

Fourth

497.2
68.8
3.2
0.02
0.3025

Fourth

353.2
5.8
(7.7)
(0.06)
0.2875

Third

33.95
29.80
31.75
12,385

Third

34.88
28.95
32.03
14,732

Third

23.69
20.50
21.63
184

Third

23.63
18.75
20.94
150

Total

2,687.7
579.2
287.9
1.91
1.1950

Total

2,341.7
492.7
240.9
1.66
1.1200

Fourth

32.00
28.60
28.65
12,716

Fourth

35.70
31.00
35.25
10,888

Fourth

21.75
19.25
20.13
83

Fourth

23.03
20.13
22.97
102

Comparative amounts have been restated to reflect the split of common shares on a two for one basis on May 10, 1999.

T H E E N E R G Y B R I D G E

Five Year Consolidated Highlights

FINANCIAL AND OPERATING INFORMATION 1
(Canadian dollars in millions, except per share amounts)

Segmented Earnings

Liquids Pipelines
Gas Distribution 2
International
Gas Pipelines and New Business Development
Energy Services
Corporate and Other

Earnings Applicable to Common Shareholders

Cash Flow Data
Cash provided from operating activities
Capital expenditures
Dividends paid on common shares

Operating Data
Liquids Pipelines 3

Deliveries (thousands of barrels per day)
Barrel miles (billions)
Average haul (miles)

Gas Distribution

Distribution volume (billion cubic feet)
Number of active customers (thousands)
Degree day deficiency 4 (degrees Celsius)

Actual
Forecast based on normal weather

1999

165.3
99.2
28.7
31.2
(2.5)
(34.0)

287.9

1998

143.2
100.2
24.3
6.3
(6.2)
(26.9)

240.9

495.1
783.7
186.4

312.4
1,388.4
168.3

2,023
696
946

402
1,466

3,460
4,060

2,136
771
989

397
1,414

3,352
4,079

1997

108.4
132.1
16.1
(2.4)
(7.5)
(29.4)

217.3

437.8
651.4
147.1

2,083
771
1,014

428
1,362

4,011
4,003

1996

92.6
111.8
4.8
–
–
(28.9)

180.3

479.6
560.5
125.9

1,970
768
1,069

429
1,307

4,209
4,058

1995

80.2
75.5
1.6
–
–
(26.9)

130.4

415.4
428.7
116.3

1,754
771
1,204

391
1,264

3,748
3,955

1
2
3
4

Certain comparative amounts have been reclassified to conform with the current year’s basis of presentation.
The highlights of the Gas Distribution activities reflect the results of Enbridge Consumers Gas and other gas distribution assets on a quarter lag basis of consolidation.
Liquids Pipelines operating highlights include the statistics of the 15.3% owned portion of the mainline system located in the United States.
Degree day deficiency is a measure of coldness. It is calculated by accumulating for each day in the fiscal period the total number of degrees by which the daily mean temperature fell below
18 degrees Celsius. The figures given are those accumulated in the Toronto area.

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

Five Year Consolidated Highlights

SHAREHOLDER AND INVESTOR INFORMATION 1
(per share amounts in Canadian dollars)

Average common shares outstanding weighted

monthly during the year (thousands)

Number of registered common shareholders at year end

150,995
8,877

145,448
9,207

137,808
10,036

124,330
10,060

113,582
8,824

1999

1998

1997

1996

1995

Common Share Trading (TSE and ME)
High
Low
Close
Volume (millions)

Per Common Share Data
Earnings applicable to common shareholders
Cash provided from operating activities
Dividends on common shares

Financial Ratios
Return on average common shareholders’ equity 2
Return on average capital employed 3
Debt to debt plus shareholders’ equity 4
Debt to total capital employed
Earnings coverage of interest 5
Dividend payout ratio 6

36.33
28.60
28.65
51.8

1.91
3.28
1.195

14.3%
6.6%
67.4%
63.7%
2.0x
62.6%

35.70
28.95
35.25
61.5

1.66
2.15
1.120

13.8%
6.6%
69.7%
64.8%
2.0x
67.7%

32.85
19.53
32.70
55.3

1.58
3.18
1.060

14.2%
7.0%
67.7%
62.5%
2.4x
67.3%

21.00
15.88
19.98
52.2

1.45
3.86
1.015

15.0%
7.6%
68.4%
62.5%
2.3x
70.0%

16.50
13.44
15.94
54.1

1.15
3.66
1.000

13.2%
7.0%
69.1%
62.7%
1.8x
87.0%

1
2
3

4
5
6

Comparative amounts have been restated to reflect the split of common shares on a two for one basis on May 10, 1999 and current year classifications.
Earnings applicable to common shareholders divided by average common equity (weighted monthly during the year).
Sum of earnings, minority interest and after tax interest expense divided by average capital employed (weighted monthly during the year). Capital employed is equal to the sum of shareholders’
equity, non controlling (minority) interest, deferred income taxes, deferred credits, and total debt (excluding short term borrowings which finance gas in storage).
Total long term debt (including current portion) divided by the sum of total long term debt, shareholders’ equity and non controlling (minority) interest.
Sum of earnings before income taxes, minority interest and interest expense, divided by interest expense.
Dividends per common share divided by earnings per share applicable to common shareholders.

T H E E N E R G Y B R I D G E

Shareholder and Investor Information

Common and Preferred Shares

Debentures

Annual Meeting

The Common Shares of Enbridge Inc. trade in
Canada on the Toronto Stock Exchange under
the ticker symbol “ENB” and in the United
States on The NASDAQ National Market under
“ENBR”. The Preferred Shares, Series A, of
Enbridge Inc. trade in Canada on the Toronto
Stock Exchange under the symbol “ENB.PR.A”.

Registrar and Transfer
Agent in Canada

CIBC Mellon Trust Company
320 Bay Street, ground floor
Toronto, Ontario M5H 4A6
Telephone: (416) 643-5000
Toll free: (800) 387-0825
Internet: www.cibcmellon.ca
CIBC Mellon Trust Company also has offices in
Halifax, Montreal, Winnipeg, Calgary, Regina
and Vancouver.

Co-Registrar and Co-Transfer
Agent in the United States

ChaseMellon Shareholder Services L.L.C.
120 Broadway, 13th floor
New York, NY, 10271 U.S.A.
Attention: Stock Transfer
Toll free: (800) 526-0801

Preferred Securities

Enbridge Preferred Securities, Series B and C,
trade in Canada on the Toronto Stock Exchange
under the ticker symbols “ENB.PR.B” and
“ENB.PR.C”, respectively. The registrar and
transfer agent is Montreal Trust Company.

The registrar and trustee for Enbridge Deben-
tures is Montreal Trust Company — Montreal,
Toronto, Winnipeg, Edmonton and Vancouver.

The Annual Meeting of Shareholders will be held
at the Palliser Hotel, Calgary, Alberta, Canada,
at 1:30 p.m. on Thursday, April 27, 2000.

Auditors

Form 40-F

PricewaterhouseCoopers LLP

Shareholder Inquiries

If you have inquiries regarding the following:
(cid:2) Dividend Reinvestment and Share Purchase Plan
(cid:2) change of address
(cid:2) share transfer
(cid:2) lost certificates
(cid:2) dividends
(cid:2) duplicate mailings
Please contact the registrar and transfer agent
— CIBC Mellon Trust Company in Canada or
ChaseMellon in the United States.

Other Investor Inquiries

If you have inquiries regarding the following:
(cid:2) additional financial or statistical information
(cid:2) industry and company developments
(cid:2) latest news releases or investor presentations
Please contact Enbridge Investor Relations or
visit Enbridge’s web site at www.enbridge.com.

Investor Relations

Director, Investor Relations
Enbridge Inc.
2900, 421 - 7th Avenue S.W.
Calgary, Alberta, Canada T2P 4K9
Toll free: (800) 481-2804
Facsimile: (403) 231-5989

The Corporation files annually with the Securi-
ties and Exchange Commission of the United
States a report known as the Annual Report
on Form 40-F. Copies of the Form 40-F are
available, free of charge, upon written request
to the Corporate Secretary of the Corporation.

Dividend Reinvestment and
Share Purchase Plan, and
Dividend Direct Deposit

Enbridge Inc. offers a Dividend Reinvestment
and Share Purchase Plan that enables share-
holders to reinvest their cash dividends in
common shares and to make additional cash
payments for purchases at the market price. The
Company also offers Dividend Direct Deposit
which enables shareholders to receive dividends
by electronic fund transfer to the bank account
of their choice in Canada. Details may be
obtained from the Investor Information section
of the Enbridge web site at www.enbridge.com,
or by contacting CIBC Mellon Trust Company at
any of the locations listed above.

Registered Office

Enbridge Inc.
2900, 421 - 7th Avenue S.W.
Calgary, Alberta, Canada T2P 4K9
Telephone: (403) 231-3900
Facsimile: (403) 231-3920
Internet: www.enbridge.com

Le présent document est disponible en français.

2000 Dividend Information for Common Shares and Preferred Shares, Series A

Record date
Payment date
Common Share Dividend Reinvestment Plan (DRIP) enrolment cut-off date
Common Share Purchase Plan cut-off date for DRIP

(cheques can be post-dated to the payment date)

1st Q

Feb. 11
March 1
Feb. 4
Feb. 23

2nd Q

May 12
June 1
May 5
May 25

3rd Q

Aug. 11
Sept. 1
Aug. 3
Aug. 25

4th Q

Nov. 17
Dec. 1
Nov. 10
Nov. 24

Corporate Information

BOARD OF DIRECTORS

James J. Blanchard
Senior Partner
Verner, Liipfert, Bernhard,
McPherson & Hand, Attorneys
Beverly Hills, Michigan

J. Lorne Braithwaite
President and Chief Executive Officer
Cambridge Shopping Centres Limited
Thornhill, Ontario

André Caillé
President and Chief Executive Officer
Hydro-Québec,
Montreal, Quebec

E. Susan Evans
Company Director
Calgary, Alberta

William R. Fatt
Chairman and Chief Executive Officer
Fairmont Hotels & Resorts,
Toronto, Ontario

F. William Fitzpatrick
Company Director
Paradise Valley, Arizona

Richard L. George
President and Chief Executive Officer
Suncor Energy Inc.,
Calgary, Alberta

Louis D. Hyndman
Senior Partner, Field Atkinson
Perraton, Barristers & Solicitors,
Edmonton, Alberta

Brian F. MacNeill
President & Chief Executive Officer
Enbridge Inc.,
Calgary, Alberta

Robert W. Martin
Company Director,
Toronto, Ontario

Donald J. Taylor
Chairman,
Enbridge Inc.,
Jacksons Point, Ontario

E N B R I D G E 1 9 9 9 A N N U A L R E P O R T

SENIOR MANAGEMENT

Brian F. MacNeill
President & Chief Executive Officer

Mel F. Belich
Senior Vice President, International
Development & Corporate Law;
Chairman, Enbridge International Inc.

J. Richard Bird
Senior Vice President, Corporate Planning
& Development and President, Enbridge
Consumers Energy Inc.

Patrick D. Daniel
President & Chief Operating Officer,
Energy Delivery

Bonnie D. DuPont
Senior Vice President, Human Resources
& Public Affairs

Stephen J.J. Letwin
President & Chief Operating Officer,
Energy Services

Rudy G. Riedl
President, Enbridge Consumers Gas

Derek P. Truswell
Senior Vice President & Chief
Financial Officer

Stephen J. Wuori
President, Enbridge Pipelines Inc.

Happy Birthday Enbridge

Enbridge Inc. celebrated its 50th anniversary in 1999 — the company
that became Enbridge in 1998 began life when it was incorporated
as Interprovincial Pipe Line in April 1949. Employees organized over
40 events in centres in North and South America. Celebrations ranged
from community events to dinners, and from golf tournaments to the
’50s-style family picnic shown here for over 600 Edmonton area
employees, annuitants and their families. Federal Justice Minister and
Edmonton MP Anne McLellan was one of the guests.

Designed and Produced by Rivard Communications Inc., Calgary Printed by Ronalds Printing, Calgary

Enbridge common shares trade on the Toronto Stock Exchange in

Canada under the symbol “ENB” and on The NASDAQ National

Market in the United States under the symbol “ENBR.”

For more information contact:

Enbridge Inc.

2900 Canada Trust Tower

421 - 7th Avenue S.W.

Calgary, Alberta, Canada T2P 4K9

Telephone: (403) 231-3900

Fax: (403) 231-3920